Exhibit 99.1 Business Update October 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 and 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, delays, contractual disputes, 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 issues, property damage and operational issues; • risks associated with cost allocation resulting in higher rates for utility bundled service customers because of possible customer bypass or departure for other electricity providers such as CCAs and Electric Service Providers; • 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; and • risks associated with the operation of transmission and distribution assets and power generating facilities, including public and employee safety issues, the risk of utility assets causing wildfires, failure, availability, efficiency and output of equipment and facilities, and availability and cost of spare parts. 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. October 31, 2018 1
Updated (U) or New (N) from July 2018 Business Table of Contents Page Update EIX Shareholder Value 3 SCE Highlights, SCE Long-Term Growth Drivers, Regulatory Model 4-6 U Wildfire Legislation Update 7N 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; GS&RP Overview 17-21 N,U Operational Excellence 22 U EIX Responding to Industry Change, Edison Energy Group Summary 23-24 U Annual Dividends Per Share 25 Appendix 2018 General Rate Case Overview 27 Historical Capital Expenditures 28 Capital Expenditure and Rate Base Detailed Forecast 29 U ESG Strategy 30 Power Grid of the Future, Grid Modernization 31-34 SCE Customer Demand Trends 35 SCE Bundled Revenue Requirement, System Average Rate Historical Growth 36-37 CCA Overview, Residential Rate Reform and Other 38-41 U SCE Rates and Bills Comparison 42 U Third Quarter 2018 Earnings Summary, Results of Operations, Non-GAAP Reconciliations 43-48 N,U October 31, 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 • 9.8% 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 and within Edison Energy Strategy target payout ratio of 45-55% of SCE • Services for large commercial and earnings industrial customers October 31, 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 Transportation electrification Electric vehicle charging Energy storage Limited Generation Exposure • Own less than 20% of its power generation • Future needs via competitive solicitations October 31, 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 • Today – Grid modernization capital expenditures included Accelerate circuit upgrades, automation, in traditional spend Grid Modernization communication, and analytics capabilities • 2019-2020 – $1.3 billion capital request in 2018 GRC at optimal locations to integrate distributed application energy resources • 2025 – CPUC target to complete grid modernization but may take longer • 2017-2022 – Multiple projects approved by CAISO in Future transmission needs to meet 60% permitting and/or construction Transmission renewables mandate in 2030, 100% clean • 2021-2045 – Future needs largely driven by CAISO energy by 2045 and to support reliability planning process • Today – Most commitments via contracts; over 560 MW procured Energy Storage SCE-owned investment opportunities under • 2018-2020 - $49 million of capital spending forecasted; existing CPUC proceedings procurement target of 580 MW by 2020; 167 MW was added to procurement targets by AB 2868 • Utility investment in programs to build and 2017 – Medium- and Heavy-Duty (MD/HD) Vehicle support the expansion of transportation Transportation Electrification (TE) plan filed January 20 Electrification of • electrification in passenger and light-, 2018 – MD/HD Vehicle TE program approved, totaling Transportation and medium- and heavy-duty vehicles and $356 million; Charge Ready II application filed, requesting Other Sectors potentially to support electrification of $760 million • other sectors of the economy 2019-2030 – Potential investments to support electrification in other sectors of the economy Utility investment and operational practices • 2018 – Filed Grid Safety & Resiliency application, Grid Safety and that address increasing wildfire risk and requesting $582 million Resiliency bolster fire prevention and suppression • Ongoing – future GRCs activities October 31, 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 October 31, 2018 6
Wildfire Legislation Update Summary of Senate Bill 901 Key Components Wildfire Mitigation • Requires annual detailed wildfire mitigation plans with objectives, preventive strategies, metrics and Plans specific details regarding de-energization protocols, vegetation management and inspections Requires CPUC approval of plan within three months unless CPUC extends deadline, failure to substantially comply with an approved plan will subject IOUs to penalties of up to $100k/offense Compliance is a factor the CPUC may consider in addressing cost recovery • Authorizes the establishment of a memorandum account to track costs until the IOU’s next GRC Forest • Enhanced forest management practices including hazardous fuels reduction, expedited removal of management dead and dying trees and chaparral, access to lands for thinning, technical assistance for permitting • 5-year assessment of greenhouse gas emissions associated with wildfires and forest management activities Commission on • Newly created commission, appointed by Governor and Legislators, charged with providing Catastrophic recommendations for changes to law that will ensure equitable distribution of catastrophic wildfire Wildfire Cost and costs. Recovery Options to include socialization of catastrophic wildfire costs in an equitable manner and/or establishment of a fund to assist in the payment of catastrophic wildfire costs Wildfire Cost • Provides guidance and added flexibility to the CPUC on evaluating the reasonableness of costs and Recovery expenses by providing a list of factors that the CPUC may consider including extreme weather, climate- related impacts Securitization • Opportunity for IOUs to securitize just and reasonable wildfire-related costs for wildfires from January 1, 2019 or those that exceed the disallowance cap from 2017 wildfires Liability Cap/Stress • Requires the CPUC to ensure that 2017 wildfire amounts disallowed for recovery do not exceed Test (2017 only) amounts which the utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service • Methodology has not been defined October 31, 2018 7
California’s GHG Emissions Overview • On October 7, 2015, Governor Brown signed SB 350, which requires a doubling of energy efficiency in existing buildings for California by 2030 • 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 • On September 10, 2018, Governor Brown signed SB 100, which requires that 60% of energy sales to customers come from renewable power by 2030 and sets a 100% clean electricity goal for the state, and issued an executive order establishing a new target to achieve carbon neutrality, both by 2045 2016 California GHG Emissions by Sector Commercial and Residential 12% Electrical Transportation Power 41% 16% 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. October 31, 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 At least 7 million light-duty • Electrify nearly one-third of IRP filing electric vehicles on residential and commercial • 80% carbon-free electricity California roads space and water heaters supported by energy storage 15% of medium-duty • Continuation of company • 2017 SCE renewable resources vehicles electrified programs and earnings portfolio = 31.6% 6% of heavy-duty vehicles incentive mechanism electrified SCE 2018-2025 program % Portfolio Breakdown budget: $289 million/year Solar 40% File annually for energy Wind 32% efficiency incentives Geothermal 24% Small Hydro 3% Biomass 1% October 31, 2018 9
SCE Historical Rate Base and Core Earnings ($ 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 $4.58 Note: Recorded rate base, year-end basis. See SCE Core EPS Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures. Since 2013, rate base excludes SONGS. October 31, 2018 10
SCE Capital Expenditure Forecast ($ billions) $13.7 Billion 2018-2020 Capital Program Traditional Capital Spending: • Capital expenditure forecast incorporates GRC, FERC and Distribution1 Transmission Generation non-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 $4.8 $4.7 GRC period to meet ultimately authorized capital $4.2 2018 Grid Modernization spending focused on safety 2 $3.8 and reliability Includes $115 million for final decision on Medium- and Heavy-Duty (MD/HD) Vehicle Transportation Electrification Alberhill spending has been deferred beyond 2020 as a result of the CPUC request for additional project justification and alternatives Excludes Charge Ready II and Grid Safety and Resiliency applications • Authorized/Actual may differ from forecast For 2009, 2012 and 2015 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 Prior modernization capital spending and, therefore, prior $3.8 $4.2 $4.8 $4.7 Forecast results may not be predictive Delta ‒‒ ‒ ‒ 1. Includes 2018 – 2020 capital expenditures of $85 million for Mobile Home Park, $49 million for Energy Storage and $4 million for Charge Ready I 2. 2017 and 2018 capital expenditures related to grid modernization are included in distribution capital expenditures Note: 2018 spending at budget levels. 2019-2020 based on 2018 CPUC GRC Tax Reform February Update testimony. See Capital Expenditure/Rate Base Detailed Forecast for further information. October 31, 2018 11
SCE Rate Base Forecast – Request Level ($ billions) 3-year CAGR of 9.8% Traditional Grid Modernization CPUC • $34.7 Rate base based on request levels from 2018 GRC Tax Reform February Update $31.8 $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 Other • Includes Tax Reform impact • Includes MD/HD Vehicle Transportation Electrification program • Excludes Charge Ready II and Grid Safety and Resiliency applications 2017 2018 2019 2020 (Authorized) Prior Forecast $26.2 $29.1 $31.8 $34.6 Delta ‒‒ ‒ 0.1 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. October 31, 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. October 31, 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 Grid Safety and Resiliency Requesting $582 million of total cost for Application filed in September 2018; all protests due in October Program (GS&RP) 2018-2020; focused on grid hardening and 2018; ongoing discovery; Prehearing Conference has yet to be (A. 18-09-002) enhanced vegetation management scheduled Wildfire Expense Memorandum Requesting authority to Application filed in April 2018; CPUC ruling issued July 2018; Account (WEMA) (A. 18-04-001) establish a WEMA to track incremental Proposed Decision issued October 29, 2018 - would make unreimbursed wildfire liability-related costs WEMA effective as of our application date, April 3, 2018 Charge Ready Program Implementation program for charger Phase 1 pilot program approved January 2016; Pilot report filed (A.14-10-014; A.18-06-015) installations and market education in May 2018; Charge Ready 2 application filed in June 2018; Scoping Memo issued October 2018 Distribution Resources Plan OIR Power grid investments to integrate Demo projects underway; Advice Letter requesting approval of (R.14-08-013) distributed energy resources deferral projects related to DRP to be filed in December 2018; system-wide implementation of ICA/LNBA maps by December 31, 2018; actively engaged in discussions on data sharing Power Charge Indifference Review, revise, and consider alternatives to the Final Decision adopted on October 11, 2018; updates current Adjustment (PCIA) OIR (R.17-06- PCIA PCIA framework to use more accurate benchmarks; initiates 026) second phase on utility portfolio optimization and cost reduction Integrated Resource Plan (IRP) “Umbrella” proceeding to consider all electric SCE’s IRP was filed August 1, 2018; opening and reply comments OIR (R.16-02-007) procurement policies/programs and filed; proceeding ongoing 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 October 31, 2018 14
CPUC Cost of Capital 7 CPUC Adjustment Mechanism Moody’s Baa Utility Index Spot Rate Moving Average (10/1/18 – 10/26/18) = 4.90% 100 basis point +/- Deadband 6 5 Rate (%) 4 Starting Value – 5.00% ROE fixed at 10.45% ROE fixed at 10.30% for 2017, independent for 2018, independent of trigger mechanism of 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 index Common Equity value, authorized ROE changes by half the difference 48% 10.45% 10.30% • Starting index value based on trailing 12 months of Preferred 9% 5.79% 5.82% Moody’s Baa index as of September 30 of each year – Long-term Debt 43% 5.49% 4.98% 5.00% Weighted Average Cost of Capital 7.90% 7.61% • Next application due April 2019 October 31, 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; based on available information, we believe most incremental costs are probable of 43% debt recovery; $0.02 per share recovery at FERC throughout year; $0.14 per share deferred in Q3 and expect to defer additional 9% preferred $0.14 per share in Q4 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 Note: All tax-affected information on this slide is based on our current combined statutory tax rate of approximately 28%. October 31, 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 $11.0 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 I, mobile home pilot programs and Transportation Electrification 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 October 31, 2018 17
Grid Safety and Resiliency Program Overview • Application at CPUC aligns with SB 901 requirements to develop wildfire risk mitigation plans and upcoming Risk Assessment Mitigation Phase (RAMP) proceeding, part of the 2021 GRC • Requesting 2018-2020 program costs due to changing risk profile and 2018 GRC timing • Eight-year program overall with expenditures beyond 2020 to be included in future GRC requests • This comprehensive risk mitigation program focuses on three key areas: Grid Hardening: Significant investment to prevent ignitions including covered conductor, non- expulsion fuses, and remote-controlled automatic reclosers Operational Enhancements: Enhanced vegetation management, infrared inspections, and proactive de-energization protocol support functions Situational Awareness: High-definition cameras to support more expedient fire suppression, weather stations, and advanced analytics to prioritize mitigation efforts Program Cost Detail – 2018-2020 ($ millions, in 2018 dollars) 2018 2019 2020 Total Capital $54 $112 $241 $407 O&M – Vegetation Management - 40 78 118 O&M – Other 8 13 35 57 Total $62 $165 $354 $582 The program’s core objectives are further hardening of our infrastructure, bolstering situational awareness capabilities and enhancing operational practices October 31, 2018 18
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, at least 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 Medium- and Heavy-Duty (MD/HD) Vehicle Charge Ready I and II Transportation Electrification Programs $356 million Total Cost1 (in nominal dollars); approved Charge Ready I - $22 million Total Cost1 (in 2014 May 2018 dollars); approved January 2016 • 5-year program • $12 million rate base opportunity included in capital spend and rate base forecasts • Approved capital spend of $242 million; O&M of $115 million • Supports close to 1,270 chargers • Included in capital spend and rate base forecasts Charge Ready II – $760 million Total Cost1 (in 2018 dollars); filed June 2018 • 4-year program, providing up to 48,000 chargers • $561 million in capital spend; O&M of $199 million • Not included in capital spend or rate base forecasts 1. Total Cost includes both O&M and capital spend October 31, 2018 19
Energy Storage CPUC Energy Storage Program Requirements: SCE 2018 Storage Portfolio • Storage Rulemaking (R.10-12-007) established 1,325 MW target for IOUs by 2024 (580 MW SCE share; spread as biennial targets 250 during 2014-20); ownership allowed up to 290 MW for SCE 200 • Flexibility to transfer across categories, expanded in Storage Rulemaking (R.15-03-011)* 200 • Decision (D. 17-04-039) added AB 2868 opportunity for programs and investments of an additional 500 MW of distribution-level energy storage systems, distributed equally 150 120 *85 MW among the IOUs (166 MW SCE share; spread as biennial targets, excess may 2018 and onward; no more than 25% can be customer offset T&D programs) MW targets 100 SCE Procurement Activities to Meet CPUC Requirements: • SCE has procured over 560 MW of energy storage (includes 60 MW of utility owned storage), ~424 MW of which is eligible to 50 count towards CPUC targets 50 • Following the recent approval of SCE’s Second Preferred Resources Pilot, SCE is ahead of its 370 MW 2018 interim Storage Targets, and ~156 MW from achieving 2020 Targets 0 • SCE filed its 2018 Energy Storage and Investment Plan on Transmission Distribution Customer March 1 Eligible storage included in 2018 Currently above The 2018 Plan included AB 2868 proposals for Energy Storage Plan (pending approval) targets Storage Programs and Investments, in addition to procurement of energy storage via other solicitations *Storage that is permitted to 2018 Cumulative SCE expects to expand on its energy storage position to count in different categories due Procurement Target meet the remainder of the 580 MW target through various to flex counting rules procurement activities October 31, 2018 20
SCE Large Transmission Projects Summary of Large Transmission Projects Remaining Investment Estimated In-Service Project Name Total Cost4 (as of September 30, 2018) Date West of Devers1,2 $848 million $671 million 2021 Mesa Substation1 $646 million $434 million 2022 Alberhill System3 $486 million $448 million — 3 Riverside Transmission Reliability $405 million $397 million 2023 Eldorado-Lugo-Mohave Upgrade $233 million $187 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. In August 2018, the CPUC approved the revised alternate decision which left the proceeding open and directed SCE to supplement the existing record with additional analysis as it relates to the Project need and alternatives. Potential revisions to the Project have not been reflected in the total cost of the Project or estimated in service date 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 October 31, 2018 21
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 • Digitization with O&M / purchased power cost reductions High performing, continuous improvement culture Ongoing Operational Excellence Efforts October 31, 2018 22
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 October 31, 2018 23
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 $104 million as of September 30, 2018 Demand Installations Solutions The Opportunity: Trusted Advisor and Solution Integrator October 31, 2018 24
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 and within target payout ratio of 45-55% of SCE’s earnings 1. 2018 Dividend annualized based on December 7, 2017 declaration increase October 31, 2018 25
Appendix October 31, 2018 26
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 ($41 million disallowance in increase in 2018 2015 GRC decision) Further increases will likely • Requests continuation of pole be required over multiple loading capital recovery GRC cycles through balancing account 1. Cost of removal is the cost to remove existing equipment that is being replaced October 31, 2018 27
SCE Historical Capital Expenditures ($ billions) $4.0 $3.9 $3.8 $3.5 $3.5 2013 2014 2015 2016 2017 October 31, 2018 28
Capital Expenditure/Rate Base Detailed Forecast ($ in billions) Detailed Capital Expenditures – 2017-2020 2017 2018 2019 2020 Total (Actual) Distribution1,2 $3.1 $3.4 $3.2 $3.1 $12.9 Transmission1 0.5 0.6 0.7 0.8 2.6 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 $17.5 Detailed Rate Base at Request Levels – 2017-2020 2017 2018 2019 2020 (Actual) Traditional Rate Base $26.2 $28.8 $31.1 $33.4 Grid Modernization - 0.3 0.7 1.3 Total $26.2 $29.1 $31.8 $34.7 1. Includes allocated capitalized overheads and general plant 2. Includes 2018 – 2020 capital expenditures of $85 million for Mobile Home Park, $49 million for Energy Storage, $4 million for Charge Ready I and $115 million for MD/HD Vehicle Transportation Electrification programs 3. 2017 and 2018 capital expenditures related to grid modernization are included in distribution capital expenditures Note: Totals may not foot due to rounding. October 31, 2018 29
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 October 31, 2018 30
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 • Voltage centrally maintained • System designed to manage fluctuating • Increasing integration of distributed resources and customer demand energy resources • 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 and cyber risk mitigation Subsidized Residential Solar • Integrated utility distribution with distributed energy resources planning Limited Electric Vehicle Charging Infrastructure Maximize Distributed Resources and Electric Vehicle Adoption • Distribution power grid infrastructure design supports customer choice and greater resiliency October 31, 2018 31
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 October 31, 2018 32
SCE Grid Modernization – Request Level ($ billions) $1.3 Billion Capital Request for 2019-20201,2 Building next generation electric grid requires accelerating traditional Transmission and Distribution / Information Technology programs and investing in new capabilities $0.65 • Upgrade portions of grid (such as 4kV system) to $0.61 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 2019 2020 or where DERs can provide grid services 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 October 31, 2018 33
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 •Sourcing DERs for grid need via competitive 2018 Activities Distributed Energy procurement, programs, and tariffs • Incentive Pilot Solicitation Resources (IDER) •DER cost-effectiveness methods •Utility incentives to pursue DERs for grid need, • Approval of DER contracts Proceeding’s Scope instead of traditional infrastructure • Programs, Tariffs, and Elements •Utility role in DER markets; utility business model Streamlined Procurement October 31, 2018 34
SCE Customer Demand Trends Kilowatt-Hour Sales (millions of kWh) 2013 2014 2015 2016 2017 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 Edison International Financial and Statistical Reports for 2017 for further information. October 31, 2018 35
SCE Bundled Revenue Requirement 2017 Bundled 2018 Bundled Revenue Revenue Requirement Requirement $millions ¢/kWh $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond 5,130 7.1 4,869 7.0 Fuel & Purchased Power Charge (44%) Distribution – poles, wires, substations, service 4,386 6.1 4,362 6.2 centers; Edison SmartConnect® Distribution Generation – owned generation investment and O&M 1,075 1.5 837 1.2 (39%) Generation (7%) Transmission – greater than 220kV 1,064 1.5 1,032 1.5 Transmission (9%) Other – CPUC and legislative public purpose (380) (0.4) 54 0.1 Other (1%) programs, system reliability investments, nuclear decommissioning, and prior-year over collections Total Bundled Revenue Requirement ($millions) $11,275 $11,154 Bundled kWh (millions) 71,961 69,856 = Bundled Systemwide Average Rate (¢/kWh) 15.7¢ 16.0¢ 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 16.0 Note: Rates in effect as of October 1, 2018. Represents bundled service which excludes Direct Access/CCA customers that do not receive generation services. October 31, 2018 36
System Average Rate Historical Growth ¢/kWh Comparative System Rates reduced due to the implementation of Average Rates 1) the SONGS Revised Settlement, including CAGR % Delta NEIL insurance benefits, 2) lower fuel & 20-yr 10-yr 5-yr EIX 16.0¢ -- purchased power costs, and 3) a lower 2015 ('98-’18) ('08-'18) ('13-'18) GRC revenue requirement that includes SCE System Average Rate 2.6% 1.6% 0.1% 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¢ Delay in 2012 GRC leads 20.0¢ Higher gas price forecast post-Katrina leads to higher rates with subsequent to shorter ramp-up of Energy Crisis and refund of over collection rate increase 18.0¢ return to normal 16.0¢ 16.0¢ 14.0¢ 12.0¢ 10.0¢ 9.7¢ 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 October 31, 2018 37
Community Choice Aggregator (CCA) Overview • Assembly Bill 1171 permits cities and counties, and Joint Powers Agencies (JPAs) 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 October 11, 2018 Commission decision changes PCIA methodology and has substantially addressed the historical subsidy to departing load that materialized when renewables market prices declined over the past 4 years Investor-Owned Utility Community Choice Aggregator o Decision also established a Phase 2, where utility optimization (IOU) (CCA) improvement, PCIA “pre-payment” options for entities serving departing load customers, and implementation of the “true- up” process will be discussed • On February 8, 2018, the Commission approved Resolution E-4907 requiring CCAs to demonstrate compliance with annual Resource Adequacy (RA) requirements prior to commencing operations • Existing Direct Access and CCA load is expected to be ~15% of SCE’s total load by the end of 2019 15-35% of SCE’s bundled service load could be part of a CCA in 2020 October 31, 2018 38
Residential Rate Design OIR Decision • CPUC Order Instituting Ratemaking R. 12-06-013 comprehensively reviewed residential rate structure, including a future transition to Time of Use (TOU) rates In March 2018, nearly 400,000 residential customers migrated to TOU rate structures Remaining eligible 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 “Super User Electric Surcharge” for usage 400% above baseline (~5% of all usage) 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: $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 Tiered Rate Tiered Rate Level Tiered Rate (Relative Rate) to Tier 1 (Relative Rate) to Tier 1 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% October 31, 2018 39
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 basic 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-days2 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 2. TOU pricing periods defined for non-residential customers per CPUC Decision D.18-07-006. Similar residential TOU definitions were filed by SCE in A.17-12-012. October 31, 2018 40
SCE Net Energy Metering Monthly Residential Solar SCE Net Metering Statistics (9/18) Installations and MW Installed • 283,374 combined residential and non-residential projects – 2,389 MW installed 7000 40 • 99.6 % solar projects • 276,774 residential (6.2% of all residential customers) – 1,499 MW • 6,600 non-residential – 890 MW 35 6000 • Approximately 4,300,792 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 MW Installed 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 September 9, 2017 Number of Residential Installations 10 • Smart Inverters required on all solar installations July 25, 2018 1000 5 • Smart Inverters with Reactive Power Priority required on all solar installations Near Term Outlook 0 0 • Combination of a flatter tiered rate and the mandatory TOU NEM 2.0 rate 2011 2012 2013 2014 2015 2016 2017 2018 structure has helped contain and reduce the cost shift; further efforts to reduce the shift through new TOU pricing periods Installations MW • Commission to revisit NEM Successor Tariff in 2019 where increased customer/demand charges and market priced export compensation rates will be explored October 31, 2018 41
SCE Rates and Bills Comparison 2017-18 Average Residential Rates (¢/kWh) KeyKey Factors Factors 27% 16.6 ₵ Higher • SCE’s residential rates are above national 13.0 ₵ average due, in part, to a cleaner fuel mix, high cost of living, and lower system load factor • SCE’s residential customer usage is lower than the national average due to mild climate and higher energy efficiency US Average SCE appliance and building standards 2017-18 Average Residential Bills • Average monthly residential bills are lower ($ per Month) than national average as higher rate levels more than offset by lower usage $128 27% Lower $93 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 861M (formerly Form 826) Data Monthly Electric Utility Sales and Revenue Data for 12 Months Ending July 2018. https://www.eia.gov/electricity/data/eia861m/index.html. October 31, 2018 42
Third Quarter Earnings Summary Q3 Q3 Key SCE EPS Drivers4 2018 2017 Variance Revenue 5,6,7 $ (0.03) Basic Earnings Per Share (EPS)1 - CPUC revenue (0.02) SCE $ 1.64 $ 1.43 $ 0.21 - FERC revenue (0.01) EIX Parent & Other (0.07) 0.01 (0.08) Lower O&M 0.08 Higher depreciation (0.02) Basic EPS $ 1.57 $ 1.44 $ 0.13 Higher net financing costs (0.02) Less: Non-core Items Income tax 6,7 0.18 Total core drivers $0.19 SCE2 $ 0.02 $ — $ 0.02 Non-core items 2 0.02 EIX Parent & Other3 (0.01) — (0.01) Total $0.21 Total Non-core $ 0.01 $ — $ 0.01 Key EIX EPS Drivers Core Earnings Per Share (EPS) EIX parent — Tax benefits in 2017 and Tax Reform $ (0.05) SCE $ 1.62 $ 1.43 $ 0.19 EEG — Tax benefits in 2017 (0.02) EIX Parent & Other (0.06) 0.01 (0.07) Total core drivers $ (0.07) Core EPS $ 1.56 $ 1.44 $ 0.12 Non-core items3 (0.01) Total $ (0.08) 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. Impact of the elimination of the GHG Reduction Funding Program in the Revised San Onofre Settlement Agreement 3. Impact of loss on sale of SoCore Energy 4. SCE’s 2018 core EPS drivers other than income taxes are adjusted to reflect consistent tax rates; income tax line item includes impact of change in tax rate 5. Excludes San Onofre revenue of $(0.15), depreciation of $0.12, property taxes of $0.01 which was offset by income tax of $0.02 6. Excludes $0.09 of income tax expenses related to Tax Reform refunded to customers 7. Excludes $0.27 of higher income tax expenses for incremental tax repair deductions, pole-loading program-based cost of removal and tax accounting method changes Note: Diluted earnings were $1.57 and $1.43 per share for the three months ended September 30, 2018 and 2017, respectively. October 31, 2018 43 43
Year to Date Earnings Summary YTD YTD Key SCE EPS Drivers4 2018 2017 Variance Revenue 5,6,7 $0.04 Basic Earnings Per Share (EPS) 1 - CPUC revenue 0.02 SCE $ 3.43 $ 3.44 $ (0.01) - FERC and other operating revenue 0.02 Higher O&M (0.10) EIX Parent & Other (0.34) (0.03) (0.31) Lower depreciation 0.01 Basic EPS $ 3.09 $ 3.41 $ (0.32) Higher net financing costs (0.08) Income taxes 6,7 0.16 Less: Non-core Items Other (0.06) SCE2 $ 0.02 $ — $ 0.02 - Property and other taxes (0.05) - Other income and expenses (0.01) EIX Parent & Other3 (0.14) — (0.14) Total core drivers $ (0.03) 2 Total Non-core $ (0.12) $ — $ (0.12) Non-core items 0.02 Total $ (0.01) Core Earnings Per Share (EPS) Key EIX EPS Drivers SCE $ 3.41 $ 3.44 $ (0.03) EIX parent $ (0.18) EIX Parent & Other (0.20) (0.03) (0.17) - Tax benefits on stock based compensation, Core EPS $ 3.21 $ 3.41 $ (0.20) IRS tax settlement in 2017 and Tax Reform (0.20) - Lower corporate expenses 0.02 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix EEG — SoCore Energy goodwill impairment in 2. Impact of the elimination of the GHG Reduction Funding Program in the Revised San 2017 partially offset by tax benefits in 2017 $ 0.01 Onofre Settlement Agreement Total core drivers $ (0.17) 3. Impact of hypothetical liquidation at book value (HLBV) accounting method and loss on sale of SoCore Energy Non-core items3 (0.14) 4. SCE’s 2018 core EPS drivers other than income taxes are adjusted to reflect consistent tax rates; income tax line item includes impact of change in tax rate Total $ (0.31) 5. Excludes San Onofre revenue of $(0.21), depreciation of $0.24, property taxes of $0.02, interest expense of $0.02 which was offset by income tax of $(0.07) 6. Excludes $0.08 of income tax benefits related to Tax Reform refunded to customers 7. Excludes $0.27 of higher income tax expenses for incremental tax repair deductions, pole- Note: Diluted earnings were $3.08 and $3.38 per share for the nine months ended September loading program-based cost of removal and tax accounting method changes 31, 2018 and 2017, respectively. October 31, 2018 44 44
SCE Annual Results of Operations ($ 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 $1,376 1. Results of operations for 2017 and 2016 do not reflect the retrospective adoption of the new accounting standards update on the presentation of the components of net periodic benefit costs for defined benefit pension and other postretirement plans Note: See Use of Non-GAAP Financial Measures. October 31, 2018 45
Earnings Non-GAAP Reconciliations ($ millions) Reconciliation of EIX GAAP Earnings to EIX Core Earnings Q3 Q3 YTD YTD Earnings Attributable to Edison International 2018 2017 2018 2017 SCE $536 $465 $1,119 $1,121 EIX Parent & Other (23) 5 (112) (11) Basic Earnings $513 $470 $1,007 $1,110 Non-Core Items SCE1 $ 7 $ – $ 7 $ – EIX Parent & Other2 (4) – (46) 1 Total Non-Core $ 3 $ – $(39) $ 1 Core Earnings SCE $529 $465 $1,112 $1,121 EIX Parent & Other (19) 5 (66) (12) Core Earnings $510 $470 $1,046 $1,109 1. Non-core income of $10 million ($7 million after-tax) for the three and nine months ended September, 2018, respectively, related to the CPUC-mandated elimination of an obligation for SCE to fund a research, development and demonstration program intended to develop technologies and methodologies to reduce GHG emissions in connection with the CPUC approval of the Revised SONGS Settlement 2. Non-core income of $1 million ($4 million loss after-tax) and non-core loss of $56 million ($46 million after-tax) for the three and nine months ended September, 2018, respectively, related to the sale of SoCore Energy. The non-core loss for the nine months ended September 31, 2018 was partially offset by income related to losses (net of distributions) allocated to tax equity investors under the HLBV accounting method Note: See Use of Non-GAAP Financial Measures. October 31, 2018 46
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. October 31, 2018 47
Use of Non-GAAP Financial Measures Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings are also used when communicating with investors and analysts regarding Edison International's earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (or losses) are defined as earnings or losses attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including sale of certain assets, and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings. A reconciliation of Non-GAAP information to GAAP information is included either on the slide where the information appears or on another slide referenced in this presentation. EIX Investor Relations Contact Sam Ramraj, Vice President (626) 302-2540 sam.ramraj@edisonintl.com Allison Bahen, Senior Manager (626) 302-5493 allison.bahen@edisonintl.com October 31, 2018 48
