EX-99.1 2 eixjuly2018businessupdat.htm EXHIBIT 99.1 EIX BUSINESS PRESENTATION
Exhibit 99.1 Business Update July 2018

Forward-Looking Statements 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 through regulated rates, including costs related to uninsured wildfire-related and mudslide- related liabilities, spending on grid modernization and other capital spending incurred prior to explicit regulatory approval; • ability to obtain sufficient insurance at a reasonable cost, including insurance relating to SCE's nuclear facilities and wildfire- related and mudslide-related exposure, and to recover the costs of such insurance or, in the absence of insurance, the ability to recover uninsured losses; • decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities, including determinations of authorized rates of return or return on equity, the 2018 GRC, the recoverability of wildfire-related and mudslide-related costs, and delays in regulatory actions; • ability of Edison International or SCE to borrow funds and access the bank and capital markets on reasonable terms; • actions by credit rating agencies to downgrade our credit ratings or those of our subsidiaries or to place those ratings on negative watch or outlook; • risks associated with the decommissioning of San Onofre, including those related to public opposition, permitting, governmental approvals, on-site storage of spent nuclear fuel, and cost overruns; • extreme weather-related incidents and other natural disasters (including earthquakes and events caused, or exacerbated, by climate change, such as wildfires), which could cause, among other things, public safety and operational issues; • risks associated with cost allocation resulting in higher rates for utility bundled service customers because of possible customer bypass or departure due to CCAs; and • risks inherent in SCE's transmission and distribution infrastructure investment program, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable acceptance of power delivery), changes in the CAISO's transmission plans, and governmental approvals. Other important factors are discussed under the headings “Forward-Looking Statements”, “Risk Factors” and “Management’s Discussion and Analysis” in Edison International’s Form 10-K and other reports filed with the Securities and Exchange Commission, which are available on our website: www.edisoninvestor.com. These filings also provide additional information on historical and other factual data contained in this presentation. July 27, 2018 1

Updated (U) or New (N) Table of Contents from May 2018 Business Page Update EIX Shareholder Value 3 SCE Highlights, SCE Long-Term Growth Drivers, Regulatory Model 4-6 U SCE’s Approach to Addressing Wildfire Risk 7 U California’s GHG Emissions Overview, SCE’s Clean Power and Electrification Pathway 8-9 U Capital Expenditures and Rate Base History and Forecast 10-12 U 2018 General Rate Case 13 Key Regulatory Proceedings 14 U CPUC Cost of Capital 15 U 2018 Financial Assumptions 16 U Distribution and Transmission Capital Expenditure Detail 17-20 U Operational Excellence 21 EIX Responding to Industry Change, Edison Energy Group Summary 22-23 U Annual Dividends Per Share 24 Appendix 2018 General Rate Case Overview 26 Historical Capital Expenditures 27 Capital Expenditure and Rate Base Detailed Forecast 28 ESG Strategy 29 N Power Grid of the Future, Grid Modernization 30-33 SCE Customer Demand Trends 34 SCE Bundled Revenue Requirement, System Average Rate Historical Growth 35-36 U CCA Overview, Residential Rate Reform and Other 37-40 U SCE Rates and Bills Comparison 41 U Second Quarter 2018 Earnings Summary, Results of Operations, Non-GAAP Reconciliations 42-47 N,U July 27, 2018 2

EIX Strategy Should Produce Superior Value Sustained Earnings and Dividend Electric-Led Clean Energy Future Growth Led by SCE SCE Rate Base Growth Drives Earnings EIX Vision • 9.7% average annual rate base • Lead transformation of the electric growth through 2020 at request level power industry • SCE earnings should track rate base • Focus on clean energy, efficient growth electrification, grid of the future and customers’ technology choice Constructive Regulatory Structure Wires-Focused SCE Strategy • Decoupling of electricity sales • Infrastructure replacement – safety • Balancing accounts and reliability • Forward-looking ratemaking • Grid modernization – California’s low- Sustainable Dividend Growth carbon goals • Target dividend growth at higher • Operational excellence than industry average within target Edison Energy Strategy payout ratio of 45-55% of SCE • Services for large commercial and earnings industrial customers July 27, 2018 3

SCE Highlights One of the nation’s largest electric utilities • 15 million residents in service territory • 5 million customer accounts • 50,000 square-mile service area Significant infrastructure investment • 1.4 million power poles • 725,000 transformers • 118,000 miles of distribution and transmission lines • 3,200 MW owned generation Above average rate base growth driven by • Safety and reliability • California’s low-carbon objectives  Grid modernization  Electric vehicle charging  Energy storage  Transportation electrification Limited Generation Exposure • Own less than 20% of its power generation • Future needs via competitive solicitations July 27, 2018 4

SCE Long-Term Growth Drivers Description Timeframe/Regulatory Process Sustained level of infrastructure investment • Ongoing - current and future GRCs Infrastructure required until equilibrium replacement Reliability rates achieved and then maintained Accelerate circuit upgrades, automation, • Today – Grid modernization capital expenditures included communication, and analytics capabilities in traditional spend at optimal locations to integrate distributed • 2019-2020 – $1.3 billion capital request in 2018 GRC Grid Modernization energy resources application • 2025 – CPUC target to complete grid modernization but may take longer Future transmission needs to meet 50% • 2017-2022 – Multiple projects approved by CAISO in renewables mandate in 2030 and to permitting and/or construction Transmission support reliability • 2021-2030 – Future needs largely driven by CAISO planning process SCE-owned investment opportunities under • Today – Most commitments via contracts existing CPUC proceedings • $49 million of capital spending forecasted for 2018-2020 • SCE’s storage portfolio – procurement target of 580 MW by 2020 Energy Storage • Energy Storage and Distribution Deferral Application (A.) 17-12-002 - seeks contract approval of 10 MW of distribution connected storage Utility investment in programs to build and • 2016 – Charge Ready Phase I approved support the expansion of transportation • 2017 – MD/HD Transportation Electrification (TE) plan filed Electrification of electrification in passenger and light-, January 20; Five TE priority projects approved, totaling $16 Transportation and medium- and heavy-duty vehicles and million potentially to support electrification of • 2018-2030 – Charge Ready Phase II filed, totaling $760 Other Sectors other sectors of the economy million; MD/HD TE standard review project approved, totaling $356 million; potential investments to support electrification of other sectors of the economy July 27, 2018 5

SCE Decoupled Regulatory Framework Regulatory Mechanism Key Benefits Decoupling of Revenues from • Earnings not affected by variability of retail electricity sales Sales • Differences between amounts collected and authorized levels either billed or refunded • Promotes energy conservation • Stabilizes revenues during economic cycles Major Balancing Accounts • Cost-recovery related balancing accounts represented more • Sales than 53% of costs • Fuel and Purchased power • Trigger mechanism for fuel and purchased power adjustments • Energy efficiency at 5% variance level • Pension expense Advanced Long-Term • Upfront contract approvals and prudency standards provide Procurement Planning greater certainty of cost recovery (subject to compliance- related reasonableness review) Forward-looking Ratemaking • Forward and test year GRC with three-year rate cycle • Separate cost of capital mechanism July 27, 2018 6

SCE’s Approach to Addressing Wildfire Risk Prevention and Hardening the Allocation of risk and mitigation infrastructure liability • Effective fire suppression • Stronger building codes in • Policies around allocation of resources high fire risk areas financial risks, including fire • Effective vegetation • Partnering with state agencies suppression costs and management policies on improved standards for damages • Hazardous fuels reduction climate resilient infrastructure • Reforming the application of • Assessing the design and inverse condemnation with • Zoning regulations for strict liability to utilities residential and commercial operation of the system in development in high fire risk high fire risk areas including: • Addressing the high cost of areas  inspecting and fire suppression which exceed state budgets annually • Different operating protocol upgrading poles under Red Flag warnings  replacing bare overhead • Addressing increasingly high conductor with covered premiums for wildfire • Preemptively de-energizing insurance coverage lines in high fire risk areas conductor during severe wind events  Installing current- • Weather stations and high limiting, non-expulsion definition cameras to improve fuses situational awareness We continue to work towards policies and procedures that support SCE’s approach in each of the legislative, regulatory and legal pathways July 27, 2018 7

California’s GHG Emissions Overview • On October 7, 2015, Governor Brown signed SB 350, which requires that 50 percent of energy sales to customers come from renewable power and a doubling of energy efficiency in existing buildings for California by 2030  Also requires Transportation Electrification investments and Integrated Resources Planning • On September 8, 2016, Governor Brown signed SB 32, which requires statewide GHG emissions to be reduced to 40% below the 1990 level by 2030  Governor Order set a 2050 target of 80% below 1990 levels • On July 24, 2017, Governor Brown signed AB 398, which extends cap-and-trade to 2030 • On January 26, 2018, Governor Brown released an Executive Order calling for 5 million zero emission vehicles by 2030 2015 California GHG Emissions by Sector Commercial and Residential 11% Transportation Electrical 39% Power 19% Agriculture 8% Industrial 23% SCE is taking a leading role to ensure that transportation electrification plays a major part in reducing GHG and criteria pollutant emissions in California Note: Data for both charts from California Air Resources Board. July 27, 2018 8

SCE’s Clean Power and Electrification Pathway Electric Power Company Roles • Emissions targets met through • Accelerate electrification of the • Doubling of energy efficiency in optimization of renewables transportation sector existing buildings • Implementation of upcoming  More than 7 million electric • Electrify nearly one-third of IRP filing vehicles on California roads residential and commercial • 80% carbon-free electricity  15% of medium-duty space and water heaters supported by energy storage vehicles electrified • Continuation of company • 2017 SCE renewable resources  6% of heavy-duty vehicles programs and earnings portfolio = 31.6% electrified incentive mechanism  SCE 2018 program budget: % Portfolio Breakdown $289 million Solar 40%  $0.03 per share of Wind 32% estimated earnings in 2018 Geothermal 24% Small Hydro 3% Biomass 1% July 27, 2018 9

SCE Historical Rate Base and Core Earnings ($ billions, except per share data) 2012– 2017 CAGR Rate Base 6% Core Earnings 2% $27.8 $25.9 $24.6 $23.3 $21.0 $21.1 2012 2013 2014 2015 2016 2017 Core $4.20 EPS $4.10 $3.88 $4.68 $4.22 $4.58 Note: Recorded rate base, year-end basis. See SCE Core EPS Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures. Since 2013, rate base excludes SONGS. July 27, 2018 10

SCE Capital Expenditure Forecast ($ billions) $13.7 Billion 2018-2020 Capital Program Traditional Capital Spending: • Capital expenditure forecast incorporates GRC, FERC and non- Distribution1 Transmission Generation GRC CPUC spending Grid Modernization Capital Spending:  Grid Modernization 2 GRC decision pending; 2018 capital plan will allow SCE to ramp up its spending program over the three-year GRC $4.8 $4.7 period to meet ultimately authorized capital  3 2018 Grid Modernization spending focused on safety and $4.2 reliability2 $3.8  Includes $119 million of non-GRC CPUC capital for mobile home pilot program, charge ready pilot, and priority review medium- and heavy-duty (MD/HD) Transportation Electrification projects in 2018-2019  Does not reflect final decision on MD/HD Transportation Electrification resulting in capital spend increases of $38 million in 2019 and $78 million in 2020  Does not reflect proposed decisions for Alberhill construction license which would result in a reduction to FERC capital spend of $35 million in 2019 and $51 million in 2020 • Authorized/Actual may differ from forecast  Since the 2009 GRC, CPUC has approved 81%, 89%, and 92% of capital requested, respectively 2017 (Actual) 2018 2019 2020  SCE has no prior approval experience on grid modernization Prior $3.8 $4.2 $4.8 $4.7 capital spending and, therefore, prior results may not be Forecast predictive Delta ‒ ‒ ‒ ‒  Forecasted FERC capital spending subject to timely receipt of permitting, licensing, and regulatory approvals 1. Includes 2018 – 2020 capital expenditures of $105 million for Mobile Home Park, $49 million for Energy Storage, $10 million for MD/HD Transportation Electrification Priority Review, and $4 million for Charge Ready 2. 2017 and 2018 capital expenditures related to grid modernization are included in distribution capital expenditures 3. 2018 spending at budget levels Note: Forecasted capital spending includes CPUC, FERC and other spending. 2019-2020 based on 2018 CPUC GRC Tax Reform February Update testimony. See Capital Expenditure/Rate Base Detailed Forecast for further information, including potential investment excluded in forecasts. Delta represents change from May 2018 Business Update. July 27, 2018 11

SCE Rate Base Forecast – Request Level ($ billions) 3-year CAGR of 9.7% Traditional Grid Modernization CPUC $34.6 • Rate base based on request levels from $31.8 2018 GRC Tax Reform February Update $29.1 FERC $26.2 • FERC rate base, including Construction Work in Progress (CWIP), is approximately 19% of SCE’s rate base by 2020 • Reflects latest capital forecast; including the Alberhill System project Other • Includes Tax Reform impact • Includes mobile home pilot program, Charge Ready pilot, and MD/HD Transportation Electrification priority review projects 2017 2018 2019 2020 • Excludes MD/HD Transportation (Authorized) Electrification standard review project and Prior $26.2 $29.1 $31.8 $34.6 Forecast Charge Ready Phase 2 application Delta ‒ ‒ ‒ ‒ • Excludes SONGS regulatory asset Note: Weighted-average year basis. 2017 based on 2015 GRC decision. 2018-2020 CPUC based on 2018 GRC Tax Reform February Update testimony, FERC based on latest forecast and current tax law, “rate-base offset” for the 2015 GRC decision excluded because of write off of regulatory asset related to 2012-2014 incremental tax repairs. Delta represents change from May 2018 Business Update. July 27, 2018 12

2018 SCE General Rate Case (GRC) • 2018 GRC Application (A. 16-09-001) filed September 1, 2016 • Addresses CPUC jurisdictional revenue requirement for 2018-2020  Includes operating costs and capital investment  Excludes CPUC jurisdictional costs such as fuel and purchased power, cost of capital and other potential SCE capital projects (transportation electrification, Charge Ready, and storage outside of the GRC)  Excludes FERC jurisdictional transmission • SCE’s Updated Testimony for tax reform was filed February 16, 2018, and requests 2018 revenue requirement of $5.534 billion  $106 million decrease over 2017 GRC revenue requirement  Requests post test year GRC revenue requirement increases: $431 million in 2019 and $503 million in 2020  The requested increase represents an estimated 3% compound annual growth rate in total rates between 2017-2020 • GRC filing advances SCE strategy focusing on safety and reliability by continuing infrastructure investment and beginning grid modernization investments, mitigating customer rate impacts through lower operating costs Estimated 2016 2017 2018 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 GRC Rebuttal Final Application Decision Filed Intervenor Evidentiary Proposed Testimony Hearings Decision Note: Schedule was set by CPUC, but excludes timing of final decision. The schedule is subject to change over the course of the proceeding. July 27, 2018 13

SCE Key Regulatory Proceedings Proceeding Description Next Steps Key CPUC Proceedings 2018 General Rate Case Set CPUC base revenue requirement, capital Updated Testimony filed on February 16, 2018; hearing held (A. 16-09-001) expenditures and rate base for 2018-2020 March 19, 2018; oral arguments held June 20, 2018 Z-Factor Advice Letter (Advice Advice letter requesting Z-Factor recovery of Protest and reply to protests have been filed; no set timeline for Letter 3768-E) $108 million incurred to obtain a 12-month, Commission review $300 million wildfire insurance policy for 2018 Charge Ready Program Implementation program for charger Phase 1 pilot program approved January 2016; Phase 1 report (A.14-10-014) installations and market education filed in May 2018; Phase 2 filed in June 2018 2017 Transportation TE proposals to address SB 350 transportation Five priority review projects approved in January 2018; Standard Electrification (A.17-01-021) electrification objectives review projects approved in May 2018 Distribution Resources Plan OIR Power grid investments to integrate Demo projects underway; Decision on the deferral framework (R.14-08-013) distributed energy resources and distribution forecasting issued in February; Decision on investment guidance issued in March 2018 Integrated Distributed Energy Creating consistent framework for guidance, SCE launched its IDER Incentive Pilot Solicitation on January 12, Resources OIR (R. 14-10-003) planning and evaluation of Distributed Energy 2018 with Final Selection notification on May 11, 2018; Amended Resources (DERs) scoping memo issued to consider alternate DER sourcing mechanisms SONGS OII OII resolved (December 2015); Proceeding Revised Settlement Agreement reached January 2018; Decision (I.12-10-013) record reopened in May 2016 issued in July 2018 Power Charge Indifference Review, revise, and consider alternatives to the Scoping memo issued – Track 1 proposed decision in April 2018 Adjustment OIR (R.17-06-026) PCIA and Track 2 proposed decision in third quarter 2018 Integrated Resource Plan (IRP) “Umbrella” proceeding to consider all electric SCE’s IRP expected to be filed August 1, 2018 OIR (R.16-02-007) procurement policies/programs and implement SB 350 requirements Key FERC Proceedings FERC Formula Rates Transmission rate setting with annual updates Replacement rate filed on October 27, 2017 and in effect subject to refund; proceeding ongoing and settlement discussions are continuing July 27, 2018 14

CPUC Cost of Capital 7 CPUC Adjustment Mechanism Moody’s Baa Utility Index Spot Rate Moving Average (10/1/17 – 04/30/18) = 4.32% 100 basis point +/- Deadband 6 5 Rate Rate (%) 4 Starting Value – 5.00% ROE fixed at ROE fixed at 10.45% for 2017, 10.30% for 2018, independent of independent of trigger mechanism trigger mechanism 3 10/1/12 10/1/13 10/1/14 10/1/15 10/1/16 10/1/17 10/1/18 10/1/19 Two year settlement approved for 2018-2019 Settlement • ROE adjustment based on 12-month average of Terms (2018- Moody’s Baa utility bond rates, measured from CPUC Authorized 2019) October 1 to September 30 Capital Structure 2017 2018-2019 • If index exceeds 100 bps deadband from starting Common Equity 48% 10.45% 10.30% index value, authorized ROE changes by half the difference Preferred 9% 5.79% 5.82% Long-term Debt 43% 5.49% 4.98% • Starting index value based on trailing 12 months of Moody’s Baa index as of September 30 of each Weighted Average Cost of Capital 7.90% 7.61% year – 5.00% July 27, 2018 15

2018 Financial Assumptions ($ billions) SCE Capital Expenditures SCE Weighted Average Rate Base Distribution $3.4 Traditional $28.8 Transmission 0.6 Grid Mod 0.3 Generation 0.2 2018 Request $29.1 2018 Plan $4.2 • Based on 2018 budgeted expenditures at SCE • FERC comprises about 20% of total rate base in 2018 • Based on GRC update submitted February 2018; incorporates impact of tax reform SCE Authorized Cost of Capital Other Items CPUC Return on Equity 10.3% • Incremental wildfire insurance costs expected to be $0.38 per CPUC Capital Structure 48% equity share relative to our current GRC request; continuing to assess probability of recovery; expect to defer $0.30 per share as a 43% debt regulatory asset if the premiums are deemed probable of recovery 9% preferred • Energy efficiency of $0.03 per share FERC Return on Equity 11.5% with incentives • Revenues recorded at 2017 levels until 2018 GRC decision is (subject to refund pending received (decision retroactive to January 1, 2018) FERC decision) • 2018 EIX Parent and Other core EPS guidance range: ($0.25) to ($0.30) per share  Holding company drag of 2 cents per share per month  Includes EPS estimate for Edison Energy; continue to target breakeven run rate by year-end 2019 EIX will provide 2018 earnings guidance after a final decision in the SCE 2018 General Rate Case Note: All tax-affected information on this slide is based on our current combined statutory tax rate of approximately 28%. July 27, 2018 16

SCE Distribution System Investments Distribution Trends • Continued focus on safety and reliability with infrastructure replacement representing 45% of total 2018 – 2020 Capital Spending Forecast distribution capital spend, but not yet reaching for Distribution including Grid Modernization1,2 equilibrium replacement rate $10.9 Billion  Includes pole loading replacement program and overhead conductor replacements Load Other • Distribution grid requires upgrades to circuit Growth New Service capacity, automation, and control systems to Connections Grid support reliability as use of distributed energy Modernization2 resources increases • Includes grid modernization capital which is expected to become a larger portion of spend beyond 2018 2018-2020 Capital Spending Drivers General Plant Infrastructure • Automation of over 850 distribution circuits Replacement • Over 2,000 miles of cable replacements • 4kV cutovers/removals • Distribution preventive maintenance • Overhead conductor replacements • Circuit breaker replacements/upgrades 1. Other includes GRC energy storage, Charge Ready Pilot and mobile home pilot programs 2. 2018 Grid Modernization spending, included in distribution, is focused on safety and reliability; most spending focused on integration of distributed energy resources has been deferred July 27, 2018 17

SCE Transportation Electrification (TE) Proposals • By 2030, SCE calls for:  an electric grid supplied by 80 percent carbon-free energy supported by 10 GWs of energy storage,  more than 7 million light-duty electric vehicles on California roads,  15% of medium-duty and 6% of heavy-duty vehicles to be electrified, and  using electricity to power nearly one-third of space and water heaters in increasingly energy-efficient buildings • To support around 7 million electric vehicles in California by 2030, California needs substantial investment in charging ports MD/HD Transportation Electrification Programs Charge Ready Phase I and II MD/HD TE Priority Review Programs – $16 million Total • Range anxiety and EV awareness must be addressed Cost1; approved January 2018 through significant deployment of EV fueling infrastructure and increased market education and • Residential Make-Ready Rebate Pilot outreach • Urban Direct Current Fast Charge Clusters Pilot Charge Ready Pilot - $22 million Total Cost1; approved • Electric Transit Bus Make-Ready Pilot January 2016 • Port of Long Beach (POLB) Terminal Yard Tractor Pilot • $12 million rate base opportunity included in capital • POLB Rubber Tire Gantry Crane Electrification Pilot spend and rate base forecasts • All included in capital spend and rate base forecasts • Supports close to 1,270 chargers 1 MD/HD TE Program - $356 million Total Cost1 (in 2016 Charge Ready Phase 2 – $760 million Total Cost (in dollars); approved May 2018 2018 dollars); filed June 2018 • 5-year program • 4-year program, providing up to 48,000 chargers • Capital spend of $242 million; O&M of $115 million • $561 million in capital spend; O&M of $199 million • Not included in capital spend and rate base forecasts • Not included in capital spend or rate base forecasts 1. Total Cost include both O&M and capital spend. July 27, 2018 18

Energy Storage CPUC Energy Storage Program Requirements: SCE 2018 Storage Portfolio • Storage Rulemaking (R.10-12-007) established 1,325 MW target for 250 IOUs by 2024 (580 MW SCE share; spread as biennial targets during 2014-20); ownership allowed up to 290 MW for SCE 200 • Flexibility to transfer across categories, expanded in Storage 200 Rulemaking (R.15-03-011)* • Decision (D. 17-04-039) added AB 2868 opportunity for programs and investments of an additional 500 MW of distribution-level 150 120 *85 MW energy storage systems, distributed equally among the IOUs (166 excess may MW SCE share; spread as biennial targets, 2018 and onward) offset T&D MW SCE Procurement Activities to Meet CPUC Requirements: targets 100 • SCE has procured over 500 MW of energy storage, and following the recent approval of SCE’s Second Preferred Resources Pilot, 50 ~424 MW of which is eligible to count towards CPUC targets. The 50 recent approval puts SCE ahead of its 370 MW 2018 interim Storage Targets, and ~156 MW from achieving 2020 Targets • SCE filed its 2018 Energy Storage and Investment Plan on March 1 0  The 2018 Plan included AB 2868 proposals for Energy Storage Transmission Distribution Customer Programs and Investments, in addition to procurement of energy storage via other solicitations (e.g., 20 MW min. for SB Eligible storage included in 2018 Currently above 801 – 2018 Aliso Canyon ES, + any eligible storage procured Storage Plan (pending approval) targets through IDER RFO, 2018 LCR RFP)  SCE expects to expand on its energy storage position to meet *Storage that is permitted to 2018 Cumulative Procurement Target the AB 2514 storage targets through various procurement count in different categories due to flex counting rules activities July 27, 2018 19

SCE Large Transmission Projects Summary of Large Transmission Projects Remaining Investment Estimated In-Service Project Name Total Cost4 (as of June 30, 2018) Date West of Devers1,2 $848 million $716 million 2021 Mesa Substation1 $646 million $457 million 2022 Alberhill System3 $486 million $448 million 2021 Riverside Transmission Reliability $405 million $397 million 2023 Eldorado-Lugo-Mohave Upgrade $233 million $188 million 2021 FERC Cost of Capital 11.5% ROE in 2018 (subject to refund): • ROE = Requested Base of 10.3% + CAISO Participation + weighted average of individual project incentives  Application for 2018 FERC Formula recovery mechanism filed on October 27, 2017  Requested 50 bp CAISO adder; approved, but application for rehearing requested by CPUC  ROE and proposed 2018 Transmission Revenue Requirement are accepted and suspended pending settlement discussions 1. CPUC approved 2. Morongo Transmission holds an option to invest up to $400 million, or half of the estimated cost of the transmission facilities only, at the in-service date. If the option is exercised, SCE’s rate base would be offset by that amount 3. Received Proposed Decision and Alternate Proposed Decision from CPUC in April 2018 and June 2018, respectively, denying SCE’s application for a certificate of public convenience and necessity for the Alberhill System Project. 4. Total Costs are nominal direct expenditures, subject to CPUC and FERC cost recovery approval. SCE regularly evaluates the cost and schedule based on permitting processes, given that SCE continues to see delays in securing project approvals July 27, 2018 20

SCE Operational Excellence Defining Excellence Measuring Excellence Top Quartile • Employee and public safety • Safety metrics • Reliability • System performance and • Customer service reliability (SAIDI, SAIFI, MAIFI) • Cost efficiency • J.D. Power customer Optimize satisfaction • Capital productivity • O&M cost per customer • Purchased power cost • Reduce system rate growth High performing, continuous with O&M / purchased improvement culture power cost reductions Ongoing Operational Excellence Efforts July 27, 2018 21

Responding to Industry Change Long-Term Industry Trends Strategy • The technology landscape is evolving at SCE Strategy an unprecedented pace, with innovation • Clean the power system by accelerating driving advances in cost and capabilities of the de-carbonization of electricity supply distributed energy resources • Help customers make cleaner energy • Customer expectations are changing with choices to support electrification and increasing choices and alternatives, a leverage flexible energy demand growing priority of sustainability • Strengthen and modernize the grid by objectives, and flattening demand replacing aging infrastructure and • The regulatory environment for utilities is deploying technology complex, increasingly supportive of new • Achieve operational and service excellence forms of competition but unable to keep with top tier performance in safety, pace with new business models reliability, affordability, and customer • Policies both in California and globally are satisfaction setting aggressive greenhouse gas reduction targets Beyond SCE • Position Edison Energy as an independent energy advisor and integrator for large commercial and industrial customers July 27, 2018 22

Edison Energy Summary Edison Energy • Energy is a significant risk large commercial and industrial customers face. Edison Energy creates competitive advantage for market leaders by Renewables & Supply quantifying this risk and designing the portfolio solution to protect shareholder value threatened Sustainability Solutions by complex energy policies, technological advancements, and new products. • Optimized portfolio solutions based on robust Managed analytics of the customer’s energy portfolio in alignment with their goals and strategic Portfolio objectives Solution • Implementation of solutions through existing service lines or brokering with third parties • Edison International investment $106 million as of June 30, 2018 Demand Installations Solutions The Opportunity: Trusted Advisor and Solution Integrator July 27, 2018 23

EIX Annual Dividends Per Share Fourteen Years of Dividend Growth $2.42 1 $2.17 $1.92 $1.67 $1.42 $1.35 $1.28 $1.30 $1.22 $1.24 $1.26 $1.16 $1.08 $1.00 $0.80 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Target dividend growth at a higher than industry average growth rate within its target payout ratio of 45-55% of SCE earnings 1. 2018 Dividend annualized based on December 7, 2017 declaration increase July 27, 2018 24

Appendix July 27, 2018 25

2018 SCE GRC Items Carried Over New Items from 2018 Previous Intervenor from 2015 GRC GRC Testimony • Requests continuation of Tax • Capital expenditures of $1.8 • ORA - Proposed no Grid Accounting Memorandum billion for grid modernization Modernization capital Account (TAMA) adjusting capital to support improved expenditures and ~90% of revenues annually for over and safety and reliability and traditional capital expenditures undercollection of specified tax increased levels of distributed • TURN - Proposed ~22% of items energy resources (DER) Grid Modernization capital • Forecasting over $85 million in • Increased depreciation expenditures and ~85% of 2018 O&M savings from expense to reflect updated traditional capital expenditures Operational Excellence cost of removal estimates1 initiatives  Limiting cost of removal • Requests recovery for short- request to mitigate term incentive compensation customer rate impact plans for full-time employees beginning with $84 million ($41 million disallowance in increase in 2018 2015 GRC decision)  Further increases will likely • Requests continuation of pole be required over multiple loading capital recovery GRC cycles through balancing account 1. Cost of removal is the cost to remove existing equipment that is being replaced July 27, 2018 26

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

Capital Expenditure/Rate Base Detailed Forecast ($ in billions) Detailed Capital Expenditures – 2017-2020 2017 2018 2019 2020 Total (Actual) Distribution1,2 $3.1 $3.4 $3.2 $3.0 $12.7 Transmission1 0.5 0.6 0.8 0.9 2.7 Generation1 0.2 0.2 0.2 0.2 0.8 Total Traditional $3.8 $4.2 $4.1 $4.1 $16.3 Grid Modernization3 - - 0.6 0.6 1.3 Total $3.8 $4.2 $4.8 $4.7 $17.6 Detailed Rate Base at Request Levels – 2017-2020 2017 2018 2019 2020 (Actual) Traditional Rate Base $26.2 $28.8 $31.1 $33.3 Grid Modernization - 0.3 0.7 1.3 Total $26.2 $29.1 $31.8 $34.6 1. Includes allocated capitalized overheads and general plant 2. Includes 2018 – 2020 capital expenditures of $105 million for Mobile Home Park, $49 million for Energy Storage, $10 million for transportation electrification priority review, and $4 million for Charge Ready Pilot 3. 2017 and 2018 capital expenditures related to grid modernization are included in distribution capital expenditures Note: Totals may not foot due to rounding. July 27, 2018 28

Edison International’s ESG Strategy “At Edison International, we are leading the transformation of the electric power industry toward a clean energy future by focusing on opportunities in clean energy, efficient electrification, the grid of the future, and customer choice. As we pursue this vision, sustainability remains at the core of who we are and what we do.” – Pedro Pizarro, Edison International CEO Key 2018 ESG Achievements: • ESG materiality assessment completed in March 2018 identifying 19 ESG issues as priorities1 for EIX, many related to the electric-led clean energy future • Enhanced 2017 Sustainability Report issued in June 2018, including sustainability scorecard and 2017 accomplishments • Enhanced voluntary ESG reporting and disclosure practices by reporting through a pilot program developed by the Edison Electric Institute (EEI) in collaboration with investors and member companies EIX 2017 Sustainability Report can be accessed at www.edison.com/sustainability 1. A “material” ESG issue is one that has the potential to impact long-term sustainability, based on the perspectives of internal and external stakeholders. This is different from, but related to, financial materiality, which is a threshold for influencing the economic decisions of investors July 27, 2018 29

Distribution Power Grid of the Future Current State Future State One-Way Electricity Flow Variable, Two-Way Electricity Flow • System designed to distribute electricity • Distribution system at the center of the from large central generating plants power grid • Increasing penetration of distributed • System designed to manage fluctuating energy resources resources and customer demand • Voltage centrally maintained • Digital monitoring and control devices and • Limited situational awareness and advanced communications systems to visualization tools for power grid improve safety and reliability, and integrate operators DERs • Improved data management and power Renewable Generation Mandates grid operations with cyber mitigation Subsidized Residential Solar • Modernize utility distribution planning with distributed energy resources Limited Electric Vehicle Charging Infrastructure Maximize Distributed Resources and Electric Vehicle Adoption • Distribution power grid infrastructure design supports customer choice and greater resiliency July 27, 2018 30

Grid Modernization Highlights Devices that provide Devices that provide stable voltage and power quality more flexibility during outage events Future circuit designs integrate State of the art Distributed operating tools Energy Resources for utility and increase operators and flexibility engineers Smart meters that provide information to facilitate The distribution customer reliability and system will require affordability transformative technologies in planning, design, construction and operation Net benefits to customers include increased safety, High speed wireless and reliability, access to Remote sensors that collect fiber communications affordable localized information about the grid infrastructure programs, and ability to adopt Legend new clean and distributed Remote Fault Indicator Computing intelligence inside technologies High speed bandwidth field area network electrical substations (communication system) Intelligent Remote Switches Centrally controlled switched capacitor bank w/ voltage control July 27, 2018 31

SCE Grid Modernization – Request Level ($ billions) $1.3 Billion Capital Request for 2019-20201,2 $0.65 Building next generation electric grid requires accelerating traditional Transmission and Distribution / Information Technology programs and investing in $0.61 new capabilities • Upgrade portions of grid (such as 4kV system) to increase capacity, improve reliability, and address technology obsolescence • Automation to monitor and control grid equipment in real-time and improve flexibility of grid operations • Expansion of Communication Networks Capital will be deployed to achieve two primary objectives • Improving safety and reliability  Focus on worst performing circuits in conjunction with traditional infrastructure replacement activities • Increase DER integration and enable advanced operations on circuits with high forecasted penetration or where DERs can provide grid services 2019 2020 2017 and 2018 capital expenditures related to grid modernization are included in traditional capital expenditures 1. 2018 Grid Modernization spending is focused on safety and reliability and 2019-2020 spending is based on 2018 GRC Tax Reform February Update testimony; most 2018 spending focused on integration of distributed energy resources has been deferred and, if not approved in GRC decision, is expected to be requested in future GRC applications 2. Forecast excludes capitalized overheads July 27, 2018 32

Distributed Energy Resources (DER) Proceedings 2018 Activities • DER Hosting Capacity analysis • Locational Net Benefits Distribution •Integration of DERs in distribution planning and • DER forecasting and operations distribution planning Resource Plan (DRP) •Development of tools and methodologies, alignment including optimal locations & value of DERs • DER driven grid Proceeding’s Scope •Framework for Grid Modernization modernization and •Field demonstrations Elements integration into GRC • Distribution Deferral framework • Grid Needs Assessment and Distribution Deferral Opportunity Report Integrated •Define DER products & grid services 2018 Activities •Sourcing DERs for grid need via competitive Distributed Energy procurement, programs, and tariffs • Incentive Pilot Solicitation Resources (IDER) •DER cost-effectiveness methods • Approval of DER contracts •Utility incentives to pursue DERs for grid need, • Pilot Report on lessons learned Proceeding’s Scope instead of traditional infrastructure • Societal Cost Test Elements •Utility role in DER markets; utility business model • Programs, Tariffs, and Streamlined Procurement July 27, 2018 33

SCE Customer Demand Trends 2013 2014 2015 2016 2017 Kilowatt-Hour Sales (millions of kWh) Residential 29,889 30,115 29,959 29,141 29,765 Commercial 40,649 42,127 42,207 41,565 41,873 Industrial 8,472 8,417 7,589 7,056 6,559 Public authorities 5,012 4,990 4,774 4,645 4,639 Agricultural and other 1,885 2,025 1,940 1,776 1,475 Subtotal 85,907 87,674 86,469 84,183 84,311 Resale 1,490 1,312 1,075 1,794 1,568 Total Kilowatt-Hour Sales 87,397 88,986 87,544 85,977 85,879 Customers Residential 4,344,429 4,368,897 4,393,150 4,417,340 4,447,706 Commercial 554,5892 557,957 561,475 565,222 569,222 Industrial 10,584 10,782 10,811 10,445 10,274 Public authorities 46,323 46,234 46,436 46,133 46,410 Agricultural 21,679 21,404 21,306 21,233 21,045 Railroads and railways 99 105 130 133 137 Interdepartmental 23 22 22 22 24 Total Number of Customers 4,977,729 5,005,401 5,033,330 5,060,528 5,094,818 Number of New Connections 27,370 29,879 31,653 38,076 39,621 Area Peak Demand (MW) 22,534 23,055 23,079 23,091 23,508 Note: See 2017 Edison International Financial and Statistical Reports for further information. July 27, 2018 34

SCE 2018 Bundled Revenue Requirement 2017 Bundled 2018 Bundled Revenue Revenue Requirement Requirement $millions ¢/kWh $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond 5,130 7.1 4,869 7.0 Fuel & Purchased Power Charge (43%) Distribution – poles, wires, substations, service 4,386 6.1 4,362 6.2 centers; Edison SmartConnect® Distribution Generation – owned generation investment and O&M 1,075 1.5 1,075 1.5 (38%) Transmission – greater than 220kV 1,064 1.5 1,032 1.5 Generation (9%) Other – CPUC and legislative public purpose (380) (0.4) 53 0.1 Transmission (9%) programs, system reliability investments, nuclear Other (1%) decommissioning, and prior-year over collections Total Bundled Revenue Requirement ($millions) $11,275 $11,391  Bundled kWh (millions) 71,961 69,856 = Bundled Systemwide Average Rate (¢/kWh) 15.7¢ 16.3¢ SCE Systemwide Average Rate History (¢/kWh) 2010 2011 2012 2013 2014 2015 2016 2017 2018 14.3 14.1 14.3 15.9 16.7 16.2 14.8 15.7 16.3 Note: Rates in effect as of June 1, 2018. Represents bundled service which excludes Direct Access/CCA customers that do not receive generation services. July 27, 2018 35

System Average Rate Historical Growth ¢/kWh Comparative System Rates reduced due to the implementation of Average Rates 1) the SONGS Settlement, including NEIL CAGR % Delta insurance benefits, 2) lower fuel & 20-yr 10-yr 5-yr EIX 16.3¢ -- purchased power costs, and 3) a lower 2015 ('98-’18) ('08-'18) ('13-'18) GRC revenue requirement that includes SCE System Average Rate 2.7% 1.8% 0.5% PG&E 19.5¢1 20% flow-through tax benefits Los Angeles Area Inflation 2.2% 1.6% 1.5% SDG&E 24.0¢1 40% 22.0¢ Higher gas price forecast post-Katrina Delay in 2012 GRC leads leads to higher rates with subsequent to shorter ramp-up of 20.0¢ Energy Crisis and refund of over collection rate increase return to normal 18.0¢ 16.3¢ 16.0¢ 14.0¢ 12.0¢ 9.7¢ 10.0¢ 8.0¢ 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 SCE’s system average rate has grown in line with inflation over the last 25 years 1. PG&E Advice 5231-E, SDG&E Advice 3167-E July 27, 2018 36

Community Choice Aggregation (CCA) Overview • Assembly Bill 1171 permits cities and counties or a Joint Power Authority (JPA) to act as CCAs to purchase and sell electricity on behalf of the utility customers within their jurisdiction • An Order Instituting Rulemaking (OIR R.17-06-026) was opened on June 29, 2017 to review, revise, and consider alternatives to the “Power Charge Indifference Adjustment” or PCIA  The PCIA allocates a proportional share of above-market costs of SCE’s energy procurement portfolio to departing load customers to ensure remaining bundled service customers are indifferent  While not an impact on earnings, for every 1% of departing load, ~$6 million is shifted to remaining bundled service customers Investor-Owned Utility Community Choice Aggregation under the current PCIA (IOU) (CCA) • On February 8, 2018, the Commission approved Resolution E-4907 requiring CCA’s to demonstrate compliance with annual Resource Adequacy (RA) requirements prior to commencing operations • Existing Direct Access and CCA load is ~15% of SCE’s total load, and another ~15% is scheduled to join CCAs in 2019 PCIA OIR Timeline (R. 17-06-026) Q1 2018 Q2 2018 Q3 2018 Track 12 Opening/Reply Briefs Proposed Decision Final Decision Track 22 File Testimony File Opening/Reply Briefs Proposed Decision 30%-50% of SCE’s bundled service load could be part of a CCA by 2020 1. AB 117 was introduced into the Assembly 1/22/2001 by Assembly member Migden, chaptered into law 9/24/2002 2. Track 1 refers to PCIA exemptions for CARE and medical baseline customers; Track 2 refers to evaluation and possible modification of the PCIA methodology July 27, 2018 37

Residential Rate Design OIR Decision • CPUC Order Instituting Ratemaking R. 12-06-013 comprehensively reviewed residential rate structure, including a future transition to Time of Use (TOU) rates  In March 2018, nearly 400,000 residential customers migrated to TOU rate structures  Remaining residential customers to be migrated beginning October 2020 • July 2015 CPUC Decision D. 15-07-001 includes:  Transition to 2 tiered rate structure, coupled with Super-user Electric (SUE) Surcharge, by 2019  “Super User Electric Surcharge” for usage 400% above baseline (~5% of current and forecasted residential load)  Minimum bills of approximately $10/month (applied to delivery revenue only) Non-CARE1, Unbundled Rates January 2014 2019 Fixed Charge: Fixed Charge: (Single-Family) $0.94/month (Single-Family) $0.94/month (Multi-Family) $0.73/month (Multi-Family) $0.73/month Minimum Bill: Minimum Bill: $10.28/month $10.28/month 2.19 1.20 2.10 2.30 1.25 1.00 1.00 (5%) (11%) (16%) (22%) (40%) (51% of system usage) (55% of system usage) Tiered Rate Level Level Tiered Rate Tiered Rate Level Level Tiered Rate (Relative to Tier Tier Rate) 1 to (Relative (Relative to Tier Tier Rate) 1 to (Relative Tier 1: Tier 2: Tier 3: Tier 4: Tier 1: Tier 2: SUE: 100% 101-130% 131-200% >200% 100% 101-400% >400% Usage Level (% of Baseline) Usage Level (% of Baseline) 1. SCE’s California Alternate Rates for Energy (CARE) program is an income-qualifying program that reduces energy bills for eligible customers by about 30% July 27, 2018 38

Impacts of Abundant Solar Energy (Duck Curve) New Time-of-Use (TOU) Periods (CPUC approved SCE’s proposal on July 12, 2018) • In 2019, SCE is changing its TOU pricing period definition for the first time in over 30 years  All non-residential and new residential NEM 2.0 customers are served on mandatory TOU rates  3.3 million residential customers will be defaulted to TOU rates starting in Oct 20201 • Abundant mid-day renewable energy lowers prices from 8am-4pm • Highest cost period is now 4pm-9pm, all-days Season Existing Proposed On-Peak Summer Weekdays: 12-6pm Weekdays: 4-9pm Mid-Peak Summer Weekdays: 8am-12pm; 6pm-11pm Weekends: 4-9pm Winter Weekdays: 8am-9pm Weekdays and Weekends: 4-9pm Off-Peak Summer Weekdays: 11pm-8am Weekdays and Weekends: All except Weekends: All 4-9pm Winter Weekdays: 9pm-8am Weekdays and Weekends: 9pm-8am Weekends: All Super Off-Peak Winter N/A Weekdays and Weekends: 8am-4pm 1. Default will begin in Oct 2020 through end of 2021 with the option to opt-out to tiered rates; CARE and FERA customers in hot climate zones 10, 13, 14 and 15 are not eligible for default; Customers who receive Medical Baseline Allocations are not eligible for default July 27, 2018 39

Residential Solar Installations in SCE Territory Monthly Residential Solar SCE Net Metering Statistics (6/18) Installations and MW Installed • 272,177 combined residential and non-residential projects – 2,287 MW installed 7000 40 • 99.6% solar projects • 265,781 residential – 1,435 MW • 6,396 non-residential – 852 MW 35 6000 • Approximately 4,167,804 MWh/year generated 30 Key Dates 5000 July 1, 2017 25 • Official start of NEM successor tariff; customers are subject to:  4000 Mandatory TOU rate  Non-bypassable charges 20 MWInstalled  Application fees 3000 July 31, 2017 15 • Residential customers who meet this deadline are grandfathered for current TOU periods for maximum of 5 years (10 for non-residential) 2000 Number Number Residential of Installations September 9, 2017 10 • Smart Inverters required on all solar installations 1000 July 25, 2018 5 • Smart Inverters with Reactive Power Priority required on all solar installations 0 0 Near Term Outlook 2011 2012 2013 2014 2015 2016 2017 2018 • Combination of a flatter tiered rate and the mandatory TOU NEM 2.0 Installations MW rate structure has helped contain and reduce the cost shift; further efforts to reduce the shift through new TOU pricing periods Note: NEM solar installations in SCE service territory include projects with solar PV only • Commission to revisit NEM Successor Tariff in 2019 where increased less than 1 MW. customer/demand charges and market priced export compensation rates will be explored July 27, 2018 40

SCE Rates and Bills Comparison 2017-18 Average Residential Rates (¢/kWh) KeyKey Factors Factors 23% 16.3 ₵ Higher • SCE’s residential rates are above national 13.3 ₵ average due, in part, to a cleaner fuel mix, high cost of living in the state, and lower system load factor than the rest of the country. • SCE’s residential customer usage is lower than the national average due to mild US Average SCE climate and higher energy efficiency appliance and building standards. 2017-18 Average Residential Bills ($ per Month) • Average monthly residential bills are lower than national average as higher rate levels $127 29% are more than offset by lower usage. Lower $91 US Average SCE SCE’s average residential rates are above national average, but residential bills are below national average due to lower usage Source: EIA's Form 826 Data Monthly Electric Utility Sales and Revenue Data for 12 Months Ending Apr 2018. https://www.eia.gov/electricity/data/eia861m/index.html. July 27, 2018 41

Second Quarter Earnings Summary Q2 Q2 Variance Key SCE EPS Drivers2 2018 2017 Revenue3,4 $0.07 Basic Earnings Per Share (EPS)1 - CPUC revenue 0.05 SCE $0.91 $0.94 $(0.03) - FERC revenue 0.02 EIX Parent & Other (0.06) (0.09) 0.03 Higher O&M (0.08) Discontinued Operations    Lower depreciation 0.03 Higher net financing costs (0.04) Basic EPS $0.85 $0.85 $  Income taxes4 0.01 Less: Non-Core Items Property and other taxes (0.02) SCE $  $  $  Total core drivers $(0.03) Non-core items  EIX Parent & Other    Total $(0.03) Discontinued Operations    Total Non-Core Items $  $  $  Key EIX EPS Drivers Core Earnings Per Share (EPS)1 EIX Parent $(0.01) - IRS tax settlement in 2017 and Tax Reform (0.03) SCE $0.91 $0.94 $(0.03) - Lower corporate expenses 0.02 EIX Parent & Other (0.06) (0.09) 0.03 EEG - SoCore Energy goodwill impairment in 0.04 Core EPS1 $0.85 $0.85 $  2017 and other Total core drivers $0.03 Non-core items  Total $0.03 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. SCE’s 2018 core EPS drivers other than income taxes are adjusted to reflect consistent tax rates; income tax line item reflects impact of change in tax rate 3. Excludes 2017 San Onofre revenue of $(0.09), depreciation of $0.06, interest expense of $0.01 which was offset by income tax of $0.02 4. Excludes $0.07 of income tax benefits related to Tax Reform refunded to customers Note: Diluted earnings were $0.84 and $0.85 per share for the three months ended June 30, 2018 and 2017, respectively. July 27, 2018 42

Year to Date Earnings Summary YTD YTD Variance Key SCE EPS Drivers3 2018 2017 Revenue4,5 $0.07 Basic Earnings Per Share (EPS)1 - CPUC revenue 0.03 SCE $1.79 $2.01 $(0.22) - FERC and other operating revenue 0.04 EIX Parent & Other (0.27) (0.05) (0.22) Higher O&M (0.18) Discontinued Operations    Lower depreciation 0.03 Higher net financing costs (0.05) Basic EPS $1.52 $1.96 $(0.44) Income taxes5 (0.03) Less: Non-Core Items Other (0.06) SCE $  $  $  - Property and other taxes (0.04) - Other income and expenses (0.02) EIX Parent & Other2 (0.13)  (0.13) Total core drivers $(0.22) Discontinued Operations    Non-core items  Total Non-Core Items $(0.13) $  $(0.13) Total $(0.22) Core Earnings Per Share (EPS)1 Key EIX EPS Drivers SCE $1.79 $2.01 $(0.22) EIX parent $(0.12) - Tax benefits on stock based compensation, (0.15) EIX Parent & Other (0.14) (0.05) (0.09) IRS tax settlement in 2017 and Tax Reform Core EPS1 $1.65 $1.96 $(0.31) - Lower corporate expenses 0.03 EEG − SoCore Energy goodwill impairment in 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix 2017 0.03 2. Impact of hypothetical liquidation at book value (HLBV) accounting method and loss on sale of Total core drivers $(0.09) SoCore Energy 3. SCE’s 2018 core EPS drivers other than income taxes are adjusted to reflect consistent tax rates; Non-core items2 (0.13) income tax line item reflects impact of change in tax rate 4. Excludes 2017 San Onofre revenue of $(0.05), depreciation of $0.13, interest expense of $0.01 Total $(0.22) which was offset by income tax of $(0.09) 5. Excludes $0.18 of income tax benefits related to Tax Reform refunded to customers Note: Diluted earnings were $1.51 and $1.95 per share for the six months ended June 30, 2018 and 2017, respectively. July 27, 2018 43

SCE Annual Results of Operations ($ millions) • 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 20171 20161 Earnings Cost-Recovery Total Earnings Cost-Recovery Total Activities Activities Consolidated Activities Activities Consolidated Operating revenue $6,611 $5,643 $12,254 $6,504 $5,326 $11,830 Purchased power and fuel — 4,873 4,873 — 4,527 4,527 Operation and maintenance 1,902 769 2,671 1,939 798 2,737 Depreciation and amortization 2,032 — 2,032 1,998 — 1,998 Property and other taxes 372 — 372 351 — 351 Impairment and other charges 716 — 716 — — — Other operating income (8) — (8) — — — Total operating expenses 5,014 5,642 10,656 4,288 5,325 9,613 Operating income 1,597 1 1,598 2,216 1 2,217 Interest expense (588) (1) (589) (540) (1) (541) Other income and expenses 97 — 97 79 — 79 Income before income taxes 1,106 — 1,106 1,755 — 1,755 Income tax (benefit) expense (30) — (30) 256 — 256 Net income 1,136 — 1,136 1,499 — 1,499 Preferred and preference stock dividend 124 — 124 123 — 123 requirements Net income available for common stock $1,012 — $1,012 $1,376 — $1,376 Less: Non-core earnings (481) — Core Earnings $1,493 $1,376 1. Results of operations for 2017 and 2016 do not reflect the retrospective adoption of the new accounting standards update on the presentation of the components of net periodic benefit costs for defined benefit pension and other postretirement plans. Note: See Use of Non-GAAP Financial Measures July 27, 2018 44

Earnings Non-GAAP Reconciliations ($ millions) Reconciliation of EIX GAAP Earnings to EIX Core Earnings Q2 Q2 YTD YTD Earnings Attributable to Edison International 2018 2017 2018 2017 SCE $297 $307 $583 $656 EIX Parent & Other (21) (29) (89) (16) Basic Earnings $276 $278 $494 $640 Non-Core Items SCE $ – $ – $ – $ – EIX Parent & Other1 2 – (42) 1 Total Non-Core $ 2 $ – $(42) $ 1 Core Earnings SCE $297 $307 $583 $656 EIX Parent & Other (23) (29) (47) (17) Core Earnings $274 $278 $536 $639 Note: See Use of Non-GAAP Financial Measures. 1. Non-core income of $3 million ($2 million after-tax) and non-core loss of $57 million ($42 million after-tax) for the three and six months ended June 30, 2018, respectively, related to the sale of SoCore Energy. The non-core loss for the six months ended June 31, 2018 was partially offset by income related to losses (net of distributions) allocated to tax equity investors under the HLBV accounting method. July 27, 2018 45

EIX Core EPS Non-GAAP Reconciliations Reconciliation of Edison International Basic Earnings Per Share to Edison International Core Earnings Per Share Earnings Per Share Attributable to Edison International 2015 2016 2017 CAGR Basic EPS 3.13 $4.02 $1.73 (26%) Non-Core Items SCE Write down, impairment and other charges (1.18) — (1.38) Re-measurement of deferred taxes — — (0.10) Insurance recoveries 0.04 — — Edison International Parent and Other Re-measurement of deferred taxes — — (1.33) Edison Capital sale of affordable housing portfolio 0.03 — — Income from allocation of losses to tax equity investor 0.03 0.02 0.04 Discontinued operations 0.11 0.03 — Less: Total Non-Core Items (0.97) 0.05 (2.77) Core EPS $4.10 $3.97 $4.50 5% Note: See Use of Non-GAAP Financial Measures. July 27, 2018 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 Sam Ramraj, Vice President (626) 302-2540 sam.ramraj@edisonintl.com Allison Bahen, Senior Manager (626) 302-5493 allison.bahen@edisonintl.com July 27, 2018 47