Exhibit 99.2 Business Update March 2019
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 formal regulatory approval; • ability to obtain sufficient insurance at a reasonable cost, including insurance relating to SCE's nuclear facilities and wildfire-related claims, and to recover the costs of such insurance or, in the event liabilities exceed insured amounts, the ability to recover uninsured losses from customers or other parties; • 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 GS&RP application, 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 Edison International or SCE’s credit ratings 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 or contributing to 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. March 1, 2019 1
Table of Contents Updated (U) or New (N) from Page October 2018 Business Update EIX Shareholder Value 3 SCE Highlights, SCE Long-Term Growth Drivers, Regulatory Model 4-6 U Wildfire Mitigation/Prevention and Legislation Summary 7-8 N,U California’s GHG Emissions Overview, SCE’s Clean Power and Electrification Pathway 9-10 U Capital Expenditures and Rate Base History and Forecast 11-13 U Key Regulatory Proceedings 14 U 2018 General Rate Case Overview 15 CPUC Cost of Capital 16 U 2019 Financial Assumptions 17 N Distribution and Transmission Capital Expenditure Detail 18-21 U Operational Excellence 22 U EIX Responding to Industry Change, Edison Energy Group Summary 23-24 U Annual Dividends Per Share 25 U Appendix 2018 General Rate Case Overview 27 Historical Capital Expenditures 28 U Capital Expenditure and Rate Base Detailed Forecast 29 U Credit Ratings Summary 30 N ESG Strategy 31 U Power Grid of the Future, Grid Modernization 32-33 SCE Customer Demand Trends 34 U SCE Bundled Revenue Requirement, System Average Rate Historical Growth 35-36 U CCA Overview, Residential Rate Reform and Other, SCE Rates and Bills Comparison 37-41 U Fourth Quarter and Full-Year 2018 Earnings Summary, Results of Operations, Non-GAAP Reconciliations 42-48 N,U March 1, 2019 2
EIX Strategy Should Produce Long-Term 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 payout ratio of 45-55% of SCE • Grid resiliency and safety earnings • Operational excellence Edison Energy Strategy • Services for large commercial and industrial customers March 1, 2019 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 • 724,000 transformers • 118,000 miles of distribution/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 March 1, 2019 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 • 2019-2020 - $26 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 • 2018 – Medium- and Heavy-Duty (MD/HD) Vehicle Electrification of support the expansion of transportation Transportation Electrification (TE) program approved, electrification in passenger and light-, totaling $356 million; Charge Ready II application filed, Transportation and medium- and heavy-duty vehicles and requesting $760 million; Charge Ready Bridge Funding Other Sectors potentially to support electrification of approved totaling $22 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, Wildfire Prevention that mitigate increasing wildfire risk and requesting $582 million of total costs (capital: $407 million) and Mitigation bolster fire prevention activities • 2019 – Filed Wildfire Mitigation Plan • Ongoing – future GRCs March 1, 2019 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 59% 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 March 1, 2019 6
Wildfire Mitigation and Prevention Summary • SCE’s 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 Increased situational awareness capabilities: High-definition cameras to support more expedient fire suppression, weather stations, and advanced analytics to prioritize mitigation efforts Enhanced operational practices: Enhanced vegetation management, enhanced overhead inspections, proactive de-energization protocol support functions, and increased use of data analytics • Filed annual compliance plan (Wildfire Mitigation Plan) detailing the near- and longer-term actions that SCE is taking to significantly reduce the risk of fire ignitions and increase emergency response and grid resiliency against future impacts of climate change • SCE’s programs (both O&M and capital) are expected to be recovered through different avenues: Discretionary capital amounts approved in the 2018 GRC Grid Safety and Resiliency Program application: $582 million of total costs ($407 million of capital) SB 901 memorandum account which will reviewed for approval during the 2021 General Rate Case proceeding SCE will spend approximately $350 million in wildfire prevention and mitigation capital in 2019 with continued investment in 2020 and beyond March 1, 2019 7
Wildfire Legislation Update Summary of Senate Bill 901 Key Components Wildfire Mitigation • Requires annual detailed wildfire mitigation plans with objectives, preventive strategies, costs, metrics Plans and specific details regarding de-energization protocols, vegetation management and inspections Filed February 6, 2019; 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 Report due July 1, 2019 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 Liability Cap/Stress Test from 2017 wildfires Liability Cap/Stress • Requires the CPUC to ensure that 2017 wildfire amounts disallowed for recovery do not exceed Test amounts which the utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service • CPUC proceeding ongoing to develop methodology March 1, 2019 8
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 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 Source: Data for both charts from California Air Resources Board; California GHG Emissions data as of 2016. March 1, 2019 9
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 • 2018 SCE renewable resources vehicles electrified programs and earnings portfolio = 36.3% 6% of heavy-duty vehicles incentive mechanism electrified SCE 2018-2025 program % Portfolio Breakdown budget: $289 million/year Solar 37% File annually for energy Wind 37% efficiency incentives Geothermal 22% Small Hydro 2% Biomass 2% March 1, 2019 10
SCE Historical Rate Base and Core Earnings ($ billions, except per share data) $29.6 $27.8 $25.9 $24.6 $23.3 $21.1 2013 2014 2015 2016 2017 2018 Core $4.22 EPS $3.88 $4.68 $4.20 $4.58 $4.42 Note: Recorded rate base, year-end basis. See SCE Core EPS Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures. Since 2013, rate base excludes SONGS. March 1, 2019 11
SCE Capital Expenditure Forecast ($ billions) Traditional Capital Spending: Distribution Transmission Generation $9.2 Billion 2019-2020 Capital Program Grid Modernization Capital Spending: • Capital expenditure forecast incorporates GRC, FERC and Grid Modernization 1 non-GRC CPUC spending $4.7 GRC decision pending; 2019 capital plan updated to $4.4 $4.5 reflect 2019 plan which will allow SCE to manage capital spending over the three year GRC period to meet what is ultimately authorized while minimizing the risk of unauthorized spending 2019 includes approximately $350 million of wildfire- related spend 2020 reflects GRC request levels; excludes Charge Ready II spending and additional wildfire-related spending; will be reconciled to authorized capital following CPUC decision • Authorized/Actual may differ from forecast For 2009, 2012 and 2015 GRC, CPUC has approved 81%, 89%, and 92% of capital requested, respectively SCE has no prior approval experience on grid 2018 (Actual) 2019 (Plan) 2020 (Request) modernization capital spending and, therefore, prior Prior Forecast $4.2 $4.8 $4.7 results may not be predictive Delta $0.2 ($0.3) ‒ 1. 2018 and 2019 capital expenditures related to grid modernization are included in distribution capital expenditures Note: 2020 based on 2018 CPUC GRC Tax Reform February Update testimony. See Capital Expenditure/Rate Base Detailed Forecast for further information. March 1, 2019 12
SCE Rate Base Forecast – Request Level ($ billions) 3-year CAGR of 9.8% Traditional Grid Modernization CPUC $34.7 • Rate base based on request levels from $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 Other • Includes Tax Reform impact • Excludes Charge Ready II and wildfire- related spend 2017 2018 2019 2020 (Authorized) Prior Forecast $26.2 $29.1 $31.8 $34.7 Delta ‒ ‒ ‒ ‒ 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. March 1, 2019 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; awaiting proposed (A. 16-09-001) expenditures and rate base for 2018-2020 decision Grid Safety and Resiliency Requesting $582 million of total cost for 2018- Application filed in September 2018; awaiting Scoping Memo; Program (GS&RP) 2020; focused on grid hardening and enhanced memorandum account approved in January 2019 (A. 18-09-002) vegetation management SB 901 Proceedings: The CPUC has opened two rulemakings The Wildfire Mitigation Plan (WMP) was filed on February 6, 2019; Wildfire Mitigation Plan OIR responsive to SB 901 (one for the evaluation of a prehearing conference was held February 26, 2019 (R. 18-10-007) wildfire mitigation plans and another for the development of a customer harm threshold Proposals for consideration in the Stress Test proceeding were Stress Test OIR (R. 19-01-006) methodology) filed on February 11, 2019; pre-hearing conference held on February 20, 2019; reply comments filed on February 25, 2019 Charge Ready Program Implementation program for charger Phase 1 pilot program approved January 2016; Pilot report filed in (A.14-10-014; A.18-06-015) installations and market education May 2018; Charge Ready 2 application filed in June 2018; Scoping Memo issued October 2018; Charge Ready Bridge Funding approved in December 2018; proceeding ongoing Distribution Resources Plan Power grid investments to integrate distributed Demo projects underway; expecting to launch deferral projects (DRP) OIR (R.14-08-013) energy resources related to DRP in Q1 2019 pending approval; implemented use of Integration Capacity Analysis (ICA)/Locational Net Benefits Analysis (LNBA) maps on December 28, 2018 Power Charge Indifference Review, revise, and consider alternatives to the Final Decision adopted on October 11, 2018; updates current PCIA Adjustment (PCIA) OIR PCIA framework to use more accurate benchmarks; initiates second (R.17-06-026) 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 implement filed; proceeding ongoing 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 March 1, 2019 14
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 $503 million in 2020 The requested increase represents an estimated 3% compound annual growth rate in total rates between 2017-2020 • GRC filing advances SCE strategy focusing on safety and reliability by continuing infrastructure investment and beginning grid modernization investments, mitigating customer rate impacts through lower operating costs Estimated 2016 2017 2018 2019 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 GRC Rebuttal Final Application Decision Filed Intervenor Evidentiary Proposed Testimony Hearings Decision Note: Schedule was set by CPUC, but excludes timing of final decision. The schedule is subject to change over the course of the proceeding. March 1, 2019 15
CPUC Cost of Capital CPUC Adjustment Mechanism 7 Moody’s Baa Utility Index Spot Rate Moving Average (10/1/18 – 02/27/19) = 4.91% 100 basis point +/- Deadband 6 5 Rate Rate (%) 4 Starting Value – 5.00% ROE fixed at 10.45% ROE fixed at 10.30% for 2017, independent for 2018, independent of trigger mechanism of trigger mechanism 3 10/1/12 10/1/13 10/1/14 10/1/15 10/1/16 10/1/17 10/1/18 10/1/19 Two year settlement approved for 2018-2019 Settlement • ROE adjustment based on 12-month average of Terms (2018- Moody’s Baa utility bond rates, measured from CPUC Authorized 2019) October 1 to September 30 Capital Structure 2017 2018-2019 • If index exceeds 100 bps deadband from starting index value, authorized ROE changes by half the difference Common Equity 48% 10.45% 10.30% • Starting index value based on trailing 12 months of Preferred 9% 5.79% 5.82% Moody’s Baa index as of September 30 of each year – Long-term Debt 43% 5.49% 4.98% 5.00% Weighted Average Cost of Capital 7.90% 7.61% • Next application due April 2019 March 1, 2019 16
2019 Financial Assumptions ($ billions) SCE Capital Expenditures SCE Weighted Average Rate Base Distribution $3.6 Traditional $31.1 Transmission 0.7 Grid Mod 0.7 Generation 0.2 2019 Request $31.8 2019 Plan $4.5 • Based on 2019 budgeted expenditures at SCE • FERC comprises about 20% of total rate base in 2019 • 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 probable of CPUC Capital Structure1 48% equity recovery; full deferral of incremental costs expected in 2019; $0.05 per share Z-Factor Advice Letter approval to be recorded 43% debt in Q1 2019 • Revenues recorded at 2017 levels until 2018 GRC decision is 9% preferred received (decision retroactive to January 1, 2018) FERC Return on Equity 11.5% with incentives • Energy efficiency incentives of $0.05 per share expected in 2019 (subject to refund pending FERC decision) • 2019 EIX Parent and Other core EPS guidance range: ($0.30) to ($0.35) per share Holding company operating expenses of 1 cent per share per month Increased interest expense driven by long-term debt needs and wider interest spreads Includes EPS estimate for Edison Energy; continue to target breakeven run rate by year-end 2019 1. On February 28, 2019, SCE filed an application with the CPUC for a waiver of compliance with this equity ratio requirement, describing that while the wildfire-related charge accrued in the fourth quarter of 2018 caused its equity ratio to fall below 47% on a spot basis as of December 31, 2018, SCE remains in compliance with the 48% equity ratio over the applicable 37- month average basis. While the CPUC reviews the waiver application, SCE is considered in compliance with the capital structure rules. Note: All tax-affected information on this slide is based on our current combined statutory tax rate of approximately 28%. Totals may not foot due to rounding. March 1, 2019 17
SCE Distribution System Investments Distribution Trends • Continued focus on safety and reliability with infrastructure replacement representing 43% of total 2019 – 2020 Capital Spending Forecast distribution capital spend, but not yet reaching for Distribution including Grid Modernization1,2 equilibrium replacement rate $7.3 Billion Includes pole loading replacement program and overhead conductor replacements Load New Service • Distribution grid requires upgrades to circuit Other Growth capacity, automation, and control systems to Connections support reliability as use of distributed energy resources increases Grid Modernization2 • Includes grid modernization capital which will become a larger portion of spend beyond 2019 and grid resiliency capital, for 2019 only, mainly driven by a covered conductor program General Plant Infrastructure 2019-2020 Capital Spending Drivers Replacement • Automation of over 850 distribution circuits • Over 2,000 miles of cable replacements • 4kV cutovers/removals • Distribution preventive maintenance • Overhead conductor replacements • Circuit breaker replacements/upgrades 1. Other includes wildfire spend, GRC energy storage, charge ready pilot programs, mobile home pilot programs and transportation electrification programs 2. 2019 Grid Modernization spending, included in distribution, is focused on safety and reliability; most spending focused on integration of distributed energy resources has been deferred March 1, 2019 18
SCE Transportation Electrification (TE) Proposals • Proposals build on SCE’s Clean Power and Electrification Pathway which is an integrated approach to reduce GHG emissions and air pollution by taking action in three California economic sectors: electricity, transportation and buildings • These programs accelerate electrification of the transportation sector, including placing at least 7 million light-duty passenger vehicles on the roads and supporting a transition to zero-emission trucks and transit Medium- and Heavy-Duty (MD/HD) Vehicle Charge Ready Bridge Funding and II Transportation Electrification Programs $356 million Total Cost1 (in nominal dollars); approved Charge Ready “Bridge” Funding - $22 million Total Cost May 2018 (in 2014 dollars); approved December 2018 • 5-year program • Additional approved capital spend of $12 million; O&M of $10 million; bridge funding must be subtracted from • Approved capital spend of $242 million; O&M of $115 any authorized Charge Ready 2 funding million • Included in capital spend and rate base forecasts • Included in capital spend and rate base forecasts • SCE to install 1000 chargers Charge Ready I Charge Ready II – $760 million Total Cost1 (in 2018 dollars); filed June 2018 1 Charge Ready I - $22 million Total Cost (in 2014 dollars); • 4-year program, providing up to 48,000 chargers approved January 2016 • $561 million in capital spend; O&M of $199 million2 • Approved capital spend of $12 million; O&M of $10 million • Not included in capital spend or rate base forecasts • Supports 1,280 chargers • Included in capital spend and rate base forecasts 1. Total Cost includes both O&M and capital spend March 1, 2019 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 during 250 2014-20); ownership allowed up to 290 MW for SCE • 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 200 investments of an additional 500 MW of distribution-level energy storage systems, distributed equally among the IOUs (166 MW SCE share; spread as biennial targets, 2018 and onward; no more than 25% can be customer programs) 150 120 *85 MW SCE Procurement Activities to Meet CPUC Requirements: excess may offset T&D • SCE has procured over 560 MW of energy storage (includes 60 MW MW of utility owned storage), ~424 MW of which is eligible to count targets towards CPUC targets 100 • 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 50 50 • SCE is presently soliciting energy storage in its Aliso Canyon Energy Storage RFO (20 MW minimum, per statute), and the 2018 Local Capacity Requirement RFP. • SCE filed its 2018 Energy Storage and Investment Plan on March 1; 0 the AB 2514 track was approved by D.18-10-036 on October 25, Transmission Distribution Customer 2018; The AB 2868 track is pending a Commission Decision The 2018 Plan included AB 2868 proposals for Energy Storage Eligible storage included in 2018 Currently above Programs and Investments, in addition to procurement of energy Storage Plan (pending approval) storage via other solicitations targets SCE expects to expand on its energy storage position to meet *Storage that is permitted to 2018 Cumulative the remainder of the 580 MW target through various Procurement Target procurement activities count in different categories due to flex counting rules March 1, 2019 20
SCE Large Transmission Projects Summary of Large Transmission Projects Remaining Investment Estimated In-Service Project Name Total Cost5 (as of December 31, 2018) Date West of Devers1,2 $848 million $607 million 2021 Mesa Substation1 $646 million $378 million 2022 Alberhill System3 $486 million $447 million — 3 Riverside Transmission Reliability4 $441 million $432 million 2023 Eldorado-Lugo-Mohave Upgrade $233 million $174 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. Riverside Transmission Reliability Project total cost is currently estimated to be $441 million, however costs could increase depending on the final route alternative selected 5. 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 March 1, 2019 21
SCE Operational Excellence Defining Excellence Measuring Excellence Top Quartile • Employee and public safety • Safety metrics • Reliability • System performance and reliability (SAIDI, SAIFI, • Customer service MAIFI) • Cost efficiency • Customer satisfaction Optimize calculation based on internal voice-of-customer • Capital productivity surveys • Purchased power cost • O&M cost per customer • Digitization • Reduce system rate growth High performing, continuous with O&M / purchased improvement culture Ongoing power cost reductions Operational Excellence Efforts March 1, 2019 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 March 1, 2019 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 $83 million as of December 31, 2018 Demand Installations Solutions The Opportunity: Trusted Advisor and Solution Integrator March 1, 2019 24
EIX Annual Dividends Per Share Fifteen Consecutive Years of Dividend Growth 1 $2.42 $2.45 $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 2019 Target dividend growth within target payout ratio of 45-55% of SCE’s earnings 1. 2019 dividend annualized based on December 6, 2018 declaration March 1, 2019 25
Appendix March 1, 2019 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 ($41 million disallowance in increase in 2018 2015 GRC decision) Further increases will likely • Requests continuation of pole be required over multiple loading capital recovery GRC cycles through balancing account 1. Cost of removal is the cost to remove existing equipment that is being replaced March 1, 2019 27
SCE Historical Capital Expenditures ($ billions) $4.4 $4.0 $3.9 $3.8 $3.5 2014 2015 2016 2017 2018 March 1, 2019 28
Capital Expenditure/Rate Base Detailed Forecast ($ in billions) Detailed Capital Expenditures – 2017-2020 2017 2018 2019 2020 Total (Actual) (Actual) (Plan) (Request) 2019-2020 Distribution1,2 $3.1 $3.5 $3.6 $3.1 $6.7 Transmission1 0.5 0.7 0.7 0.8 1.5 Generation1 0.2 0.2 0.2 0.2 0.4 Total Traditional $3.8 $4.4 $4.5 $4.1 $8.6 Grid Modernization3 - - - 0.6 0.6 Total $3.8 $4.4 $4.5 $4.7 $9.2 Detailed Rate Base at Request Levels – 2017-2020 2017 2018 2019 2020 (Authorized) (Request) (Request) (Request) 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 capital expenditures of approximately $350 million for wildfire spend in 2019 (Plan) 3. 2017, 2018 and 2019 capital expenditures related to grid modernization are included in distribution capital expenditures Note: Totals may not foot due to rounding. March 1, 2019 29
Credit Ratings Summary S&P Moody’s Fitch Date of Report January 21, 2019 January 24, 2019 January 22, 2019 Edison International Corporate / Outlook BBB/Negative Watch Baa1/Negative Watch BBB+/Negative Senior Unsecured BBB- Baa1 BBB+ Commercial Paper A-2 P-2 F2 Southern California Edison Corporate / Outlook BBB/Negative Watch A3/Negative Watch BBB+/Negative First Mortgage Bonds A- A1 A Senior Unsecured BBB A3 A- Preferred Securities BB+ Baa2 BBB Commercial Paper A-2 P-2 F2 March 1, 2019 30
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 2018 Sustainability Report is expected to be released in May/June 2019 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 March 1, 2019 31
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 March 1, 2019 32
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 March 1, 2019 33
SCE Customer Demand Trends Kilowatt-Hour Sales (millions of kWh) 2014 2015 2016 2017 2018 Residential 30,027 30,093 29,579 30,221 29,865 Commercial 42,004 42,396 42,189 42,514 42,369 Industrial 8,392 7,623 7,162 6,659 6,786 Public authorities 4,975 4,795 4,715 4,711 4,510 Agricultural and other 2,019 1,950 1,803 1,498 1,745 Subtotal 87,416 86,857 85,448 85,602 85,276 Resale 1,308 1,080 1,794 1,568 1,867 Total Kilowatt-Hour Sales 88,725 87,937 87,242 87,170 87,143 Customers Residential 4,368,897 4,393,150 4,417,340 4,447,706 4,477,508 Commercial 557,957 561,475 565,222 569,222 572,313 Industrial 10,782 10,811 10,445 10,274 10,078 Public authorities 46,234 46,436 46,133 46,410 46,059 Agricultural 21,404 21,306 21,233 21,045 20,872 Railroads and railways 105 130 133 137 131 Interdepartmental 22 22 22 24 24 Total Number of Customers 5,005,401 5,033,330 5,060,528 5,094,818 5,126,985 Number of New Connections 29,879 31,653 38,076 39,621 39,633 Area Peak Demand (MW) 23,055 23,079 23,091 23,508 23,766 Note: See Edison International Financial and Statistical Reports for 2017 for further information. March 1, 2019 34
SCE Bundled Revenue Requirement 2018 Bundled Revenue Requirement $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond 4,869 7.0 Fuel & Purchased Power Charge (44%) Distribution – poles, wires, substations, service 4,362 6.2 centers; Edison SmartConnect® Distribution Generation – owned generation investment and O&M 837 1.2 (39%) Generation (7%) Transmission – greater than 220kV 1,032 1.5 Transmission (9%) Other – CPUC and legislative public purpose 54 0.1 Other (1%) programs, system reliability investments, nuclear decommissioning, and prior-year over collections Total Bundled Revenue Requirement ($millions) $11,154 Bundled kWh (millions) 69,856 = Bundled Systemwide Average Rate (¢/kWh) 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. March 1, 2019 35
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 & 28-yr 20-yr 10-yr SCE 16.0¢ -- purchased power costs, and 3) a lower 2015 (‘90-’18) ('98-’18) ('08-'18) GRC revenue requirement that includes SCE System Average Rate 1.8% 2.6% 1.6% PG&E 19.5¢1 20% flow-through tax benefits Los Angeles Area Inflation 2.4% 2.2% 1.6% 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 rate increase 20.0¢ Energy Crisis and refund of over collection 19.0¢ return to normal 18.0¢ 16.0¢ 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 less than inflation over the last 28 years 1. PG&E Advice 5231-E, SDG&E Advice 3167-E March 1, 2019 36
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 o Decision also established a Phase 2, which will address utility portfolio optimization, PCIA “pre-payment” options for entities and Investor-Owned Utility Community Choice Aggregator individual departing load customers, and implementation of the (IOU) (CCA) “true-up” process for Resource Adequacy and Renewable Energy Credits 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 ~35% of SCE’s total load by the end of 2019 Approximately 45% of SCE’s bundled service load could be part of a CCA or Direct Access by the end of 2020 March 1, 2019 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, SCE began to migrate 400,000 residential customers 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 by 2019 “Super User Electric Surcharge” for usage 400% above baseline (~3% 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: $10.54/month 2.19 1.20 2.10 2.30 1.25 1.00 1.00 (3%) (11%) (16%) (22%) (35%) (51% of system usage) (62% 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% March 1, 2019 38
Impacts of Abundant Solar Energy (Duck Curve) New Time-of-Use (TOU) Periods (CPUC approved SCE’s proposal on July 12, 2018) • On March 1, 2019, SCE is changing its basic TOU pricing period definition for the first time in over 30 years • Abundant mid-day renewable energy lowers prices from 8am-4pm • Highest cost period is now 4pm-9pm, all-days1 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. 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 March 1, 2019 39
SCE Net Energy Metering Monthly Residential Solar SCE Net Metering Statistics (12/18) Installations and MW Installed • 294,388 combined residential and non-residential projects – 2,494 MW installed 7000 40 • 99.8 % solar projects • 287,620 residential (6.6% of all residential customers) – 1,562 MW • 6,768 non-residential – 932 MW 35 6000 • Approximately 4,363,974 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 September 9, 2017 Number Number Residential of 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 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 March 1, 2019 40
SCE Rates and Bills Comparison 2017-18 Average Residential Rates (¢/kWh) KeyKey Factors Factors 26% 16.3 ₵ Higher • SCE’s residential rates are above national 12.9 ₵ 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 the national average as higher rate levels are more than offset by lower usage $129 27% Lower $94 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 October 2018. https://www.eia.gov/electricity/data/eia861m/index.html. March 1, 2019 41
Fourth Quarter Earnings Summary Q4 Q4 Variance Key SCE EPS Drivers3 2018 2017 Revenue4,5,6 Basic Earnings Per Share (EPS)1 $ (0.06) - CPUC revenue (0.04) SCE $ (4.38) $ (0.33) $ (4.05) - FERC and other operating revenue (0.02) EIX Parent & Other (0.11) (1.34) 1.23 Higher O&M (0.03) Higher depreciation Discontinued Operations2 0.10 — 0.10 (0.02) Higher net financing costs (0.04) Basic EPS $ (4.39 ) $ (1.67 ) $ (2.72 ) Income tax4,6 0.03 Less: Non-core Items Other (0.02) SCE2 $ (5.39) $ (1.48) $ (3.91) - Property and other taxes (0.01) - Other income and expenses (0.01) EIX Parent & Other2 (0.04) (1.29) 1.25 Total core drivers $ (0.14) Discontinued Operations2 0.10 — 0.10 Non-core items2 (3.91) Total Non-core $ (5.33) $ (2.77) $ (2.56) Total $ (4.05) Core Earnings Per Share (EPS) Key EIX EPS Drivers SCE $ 1.01 $ 1.15 $ (0.14) EIX parent and other — Settlement of 1994 – 2006 EIX Parent & Other (0.07) (0.05) (0.02) California tax audits and Tax Reform $ 0.02 EEG — 2018 Edison Energy goodwill impairment (0.04) Core EPS $ 0.94 $ 1.10 $ (0.16) Total core drivers $ (0.02) 2 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix Non-core items 1.25 2. See EIX Core EPS non-GAAP reconciliation in Appendix Total $ 1.23 3. 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 4. Excludes $0.08 of income tax benefits related to Tax Reform refunded to customers 5. Excludes San Onofre revenue of $(0.21), depreciation of $0.07, property taxes of $0.01 and income tax benefits of $0.13 6. Excludes $0.01 of higher income tax benefits for incremental tax repair deductions, pole- loading program-based cost of removal and tax accounting method changes Note: Diluted earnings were $(4.39) and $(1.66) per share for the three months ended December 31, 2018 and 2017, respectively. March 1, 2019 42
Full Year 2018 Earnings Summary 2018 2017 Variance Key SCE EPS Drivers3 4,5,6 Basic Earnings Per Share (EPS)1 Revenue $ (0.02) - CPUC revenue (0.02) SCE (0.95) $ 3.10 $ (4.05) Higher O&M (0.13) EIX Parent & Other (0.45) (1.37) 0.92 Higher depreciation (0.01) Higher net financing costs (0.12) Discontinued Operations2 0.10 — 0.10 Income taxes4,6 0.19 Basic EPS $ (1.30 $ 1.73 $ (3.03 ) ) Other (0.07) - Property and other taxes (0.06) Less: Non-core Items - Other income and expenses (0.01) 2 SCE $ (5.37) $ (1.48) $ (3.89) Total core drivers $ (0.16) 2 EIX Parent & Other2 (0.18) (1.29) 1.11 Non-core items (3.89) Total $ (4.05) Discontinued Operations2 0.10 — 0.10 Total Non-core $ (5.45) $ (2.77) $ (2.68) Key EIX EPS Drivers EIX parent and other — Tax benefits on stock based Core Earnings Per Share (EPS) compensation in 2017, Tax Reform and other $ (0.16) SCE $ 4.42 $ 4.58 $ (0.16) EEG — $ (0.03) - Tax benefits in 2017 and other EIX Parent & Other (0.27) (0.08) (0.19) (0.02) - 2018 Edison Energy goodwill impairment (0.04) Core EPS $ 4.15 $ 4.50 $ (0.35) - 2017 SoCore goodwill impairment 0.03 Total core drivers $ (0.19) 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix Non-core items2 1.11 2. See EIX Core EPS non-GAAP reconciliation in Appendix Total $ 0.92 3. 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 4. Excludes $0.16 of income tax benefits related to Tax Reform refunded to customers 5. Excludes San Onofre revenue of $(0.42), depreciation of $0.31, property taxes $0.02, interest expense of $0.03 and income tax benefits of $0.06 6. Excludes $0.26 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 $(1.30) and $1.72 per share for the twelve months ended December 31, 2018 and 2017, respectively. March 1, 2019 43
SCE Wildfire-Related Charge Summary ($ millions) For the year ended December 31, 2018, the income statements include the estimated losses (established at the lower end of the reasonably estimated range of expected losses), net of expected recoveries from insurance and FERC customers, related to the 2017/2018 Wildfire/Mudslide Events (as defined in the 10-K filed on February 28, 2019) as follows: 2018 Charge for wildfire-related claims $4,669 Expected insurance recoveries (2,000) Expected revenue from FERC customers (135) Total pre-tax charge $2,534 Income tax benefit (709) Total after-tax charge $1,825 Total after-tax charge (per share) $5.60 Note: See Use of Non-GAAP Financial Measures. March 1, 2019 44
SCE Annual Results of Operations ($ 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 2018 2017 Earnings Cost-Recovery Total Earnings Cost-Recovery Total Activities Activities Consolidated Activities Activities Consolidated Operating revenue $6,560 $6,051 $12,611 $6,611 $5,643 $12,254 Purchased power and fuel — 5,406 5,406 — 4,873 4,873 Operation and maintenance 1,972 730 2,702 1,898 824 2,722 Wildfire-related claims, net of recoveries 2,669 — 2,669 ― ― ― Depreciation and amortization 1,867 — 1,867 2,032 — 2,032 Property and other taxes 392 — 392 372 — 372 Impairment and other charges (12) — (12) 716 — 716 Other operating income (7) — (7) (8) — (8) Total operating expenses 6,881 6,136 13,017 5,010 5,697 10,707 Operating (loss) income (321) (85) (406) 1,601 (54) 1,547 Interest expense (671) (2) (673) (588) (1) (589) Other income and expenses 107 87 194 93 55 148 (Loss) income before income taxes (885) — (885) 1,106 — 1,106 Income tax (benefit) expense (696) — (696) (30) — (30) Net (loss) income (189) — (189) 1,136 — 1,136 Preferred and preference stock dividend 121 — 121 124 — 124 requirements Net (loss) income available for common stock ($310) — ($310) $1,012 — $1,012 Less: Non-core items (1,750) (481) Core Earnings $1,440 $1,493 Note: See Use of Non-GAAP Financial Measures. March 1, 2019 45
Earnings Non-GAAP Reconciliations ($ millions) Reconciliation of EIX GAAP Earnings to EIX Core Earnings Q4 Q4 Earnings Attributable to Edison International 2018 2017 2018 2017 SCE ($1,429) ($109) ($310) $1,012 EIX Parent & Other (35) (436) (147) (447) Discontinued operations1 34 — 34 — Basic Earnings ($1,430) ($545) ($423) $565 Non-Core Items SCE 1,2,3 ($1,757) ($481) ($1,750) ($481) EIX Parent & Other 1,4 (12) (421) (58) (420) Discontinued operations 1 34 — 34 — Total Non-Core ($1,735) ($902) ($1,774) ($901) Core Earnings SCE $328 $372 $1,440 $1,493 EIX Parent & Other (23) (15) (89) (27) Core Earnings $305 $357 $1,351 $1,466 1. Includes income tax benefit of $34 million, income tax benefit of $66 million and income tax expense of $12 million in 2018 related to the settlement of the 1994 – 2006 California tax audit for discontinued operations, SCE and EIX parent and other, respectively. 2. Includes income of $2 million ($2 million after-tax) and $12 million ($9 million after-tax) for the quarter and year-ended December 31, 2018, respectively, and impairment charges of $716 million ($448 million after-tax) in 2017 related to the Revised San Onofre Settlement Agreement. Also includes $33 million tax expense from the re- measurement of deferred taxes as a result of Tax Reform in fourth quarter of 2017. 3. Includes 2018 charge of $2,534 million ($1,825 after-tax) related to wildfire-related claims, net of recoveries 4. Includes loss of $56 million ($46 million after-tax) related to sale of SoCore Energy in April 2018. Also includes tax expense of $433 million in fourth quarter of 2017 as a result of Tax Reform and income related to losses (net of distributions) allocated to tax equity investors under the (HLBV) accounting method of $20 million ($12 million after-tax) and $21 million ($13 million after-tax) for the quarter and year-ended December 31, 2017, respectively. Note: See Use of Non-GAAP Financial Measures. March 1, 2019 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 2018 2017 Basic EPS ($1.30) $1.73 Non-Core Items SCE Wildfire-related claims, net of recoveries (5.60) — Settlement of 1994 – 2006 California tax audits 0.20 — Write down, impairment and other as a result of Revised San 0.03 (1.38) Onofre Settlement Agreement Re-measurement of deferred taxes as a result of Tax Reform — (0.10) Edison International Parent and Other Settlement of 1994 – 2006 California tax audits (0.04) — Re-measurement of deferred taxes as a result of Tax Reform — (1.33) Sale of SoCore Energy and other (0.14) 0.04 Discontinued operations Resolution of tax issues related to EME — — Settlement of 1994 – 2006 California tax audits 0.10 — Less: Total Non-Core Items (5.45) (2.77) Core EPS $4.15 $4.50 Note: See Use of Non-GAAP Financial Measures. March 1, 2019 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 March 1, 2019 48
