EX-99.1 2 eixnovember2015businessu.htm EXHIBIT 99.1
November 19, 2015 Business Update November 2015

November 19, 2015 1 Forward-Looking Statements Statements contained in this presentation about future performance, including, without limitation, operating results, asset and rate base growth, capital expenditures, 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 are discussed under the headings “Risk Factors” and “Management’s Discussion and Analysis” in Edison International’s Form 10- K, most recent form 10-Q, and other reports filed with the Securities and Exchange Commission, which are available on our website: www.edisoninvestor.com. These filings also provide additional information on historical and other factual data contained in this presentation. This presentation combines information contained in the company’s Business Update dated October 28, 2015 and the Business Update Supplement: SCE 2015 General Rate Case Decision. The company continues to analyze the regulatory, tax and accounting implications of the final decision and preliminary conclusions maybe subject to change.

November 19, 2015 2 Table of Contents Page New (N) or Updated (U) from October 28 Business Update EIX Shareholder Value 3 SCE Highlights, Regulatory Model 4‐5 Capital Expenditures, Rate Base 6‐7 General Rate Case, Capital Expenditures and Rate Base Outlook 8‐11 N,U 2015 Guidance 12 N Growth Drivers Beyond 2017, Grid of the Future 13‐15 Distribution Resources Plan 16‐18 Energy Storage, Charge Ready Programs 19‐20 U Key Regulatory Proceedings 21 U Cost of Capital 22 U Residential Rate Reform 23‐25 N,U Operational Excellence 26 Annual Dividends Per Share 27 Appendix SCE Bundled Revenue Requirement 29 SCE Customer Rates and Demand 30‐32 U California Energy Policy 33‐35 U EIX Responding to Industry Change 36‐38 Third Quarter and YTD Earnings Summary 39‐42 N Results of Operations 43 Non‐GAAP Reconciliations 44‐46 N

November 19, 2015 3 EIX Strategy Should Produce Superior Value Sustainable Earnings and Dividend Growth Positioned for Transformative Change Rate Base and Core Earnings Growth • 7-8% average annual rate base growth through 2017 based on GRC proposed decision Constructive Regulatory Structure • Decoupling • Balancing accounts • Forward-looking ratemaking Sustainable Dividend Growth • Target payout ratio: 45-55% of SCE core earnings • Returning to target payout ratio in steps over time produces above industry-average dividend growth SCE Focus on Lower-Risk Energy Delivery • Wires assets represent over 90% of utility plant as of December 31, 20141 SCE Growth Drivers Beyond 2017 • Public safety and reliability • Distribution Resources Plan • Electric vehicle charging and storage • State environmental policy • Transmission Edison Energy Competitive Strategy • Integrate emerging technologies and business models to serve commercial and industrial customers 1. Includes assets classified as transmission, distribution and general plant

November 19, 2015 4 One of the nation’s largest electric utilities • Nearly 14 million residents in service territory • 5 million customer accounts • 50,000 square-mile service area Significant infrastructure investments • 1.4 million power poles • 700,000 transformers • 103,000 miles of distribution and transmission lines • 3,100 MW owned generation Above average annual rate base growth driven by • Public safety and reliability • Distribution Resources Plan (DRP) • Electric vehicle charging and storage • State environmental policy • Transmission SCE Highlights

November 19, 2015 5 SCE Decoupled Regulatory Model Decoupling of Regulated Revenues from Sales Major Balancing Accounts • Fuel • Purchased power • Energy efficiency • Pension-related contributions Advanced Long-Term Procurement Planning Forward-looking Ratemaking • SCE earnings are not affected by changes in retail electricity sales • Differences between amounts collected and authorized levels are either billed or refunded to customers • Promotes energy conservation • Stabilizes revenues during economic cycles • Trigger mechanism for fuel and purchased power adjustments at 5% variance level • Utility cost-recovery via balancing accounts represented more than 55% of 2014 costs • Sets prudent upfront standards allowing greater certainty of cost recovery (subject to reasonableness review) • Three-year rate case cycle • Separate multi-year cost of capital proceeding Regulatory Model Key Benefits

November 19, 2015 6 SCE Historical Capital Expenditures $2.9 $3.8 $3.9 $3.9 $3.5 $4.0 2009 2010 2011 2012 2013 2014 ($ billions)

November 19, 2015 7 $15.0 $16.8 $18.8 $21.0 $21.1 $23.3 2009 2010 2011 2012 2013 2014 SCE Historical Rate Base and Core Earnings Rate Base Core Earnings 9% 12% 2009 – 2014 CAGR Core EPS $4.68$2.68 $3.01 $3.33 $4.10 ($ billions) $3.88 Note: Recorded rate base, year-end basis. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. 2013 and 2014 rate base excludes SONGS

November 19, 2015 8 • Incorporates CPUC 2015 GRC final decision and delays in FERC spending of approximately $50 million in 2015 and $350 million in 2016 related to shift in project schedules out in time • Excludes DRP, Charge Ready program and energy storage capital spending SCE 2015-2017 Capital Expenditure Forecast Note: Forecasted capital spending subject to timely receipt of permitting, licensing, and regulatory approvals. Forecasted capital spending includes CPUC, FERC and other spending Range case includes a 12% reduction of FERC expenditures in 2016 and 2017 ($ billions) 2015-17 Total Outlook $3.9 $3.8 $4.1 $11.8 Range $3.9 $3.7 $4.0 $11.6 $3.9 $3.8 $4.1 2015 2016 2017 Distribution Transmission Generation $11.6 – $11.8 Billion Capital Program for 2015-2017 2018+ Capital Spending Outlook • SCE anticipates long-term capital spending to continue at least in the range of ~$4 billion annually, although could result in higher spending pending CPUC approval in future GRCs • FERC shift of $400 million of capital spending to 2018-2020

November 19, 2015 9 SCE 2015-2017 Rate Base Forecast • Incorporates 2015 GRC final decision, except “rate base offset” • GRC “rate base offset” excluded because of write off of regulatory asset related to 2012-2014 incremental tax repairs • Includes updated FERC capital spending forecast (rate base reductions of $0.1, $0.3 and $0.6 billion in 2015, 2016 and 2017 respectively) • FERC rate base includes Construction Work in Progress (CWIP) and is approximately 23% of SCE’s rate base outlook by 2017 • Excludes SONGS regulatory asset ($ billions) Outlook Range $23.0 $24.7 $26.5 $23.0 $24.8 $26.7 2015 2016 2017 Note: Weighted-average year basis, 2015-2017 CPUC rate base proposed decision and consolidation of CWIP projects. Rate base forecast range reflects capital expenditure forecast range. Rate base calculated under current tax law. See Accounting for GRC Decision for information on accounting impacts from rate base reduction on tax repairs 7-8% Average Annual Rate Base Growth for 2015-2017 2018+ Rate Base Outlook • Growth tied to post-2017 annual capital spending outlook of $4+ billion depending on regulatory approvals

November 19, 2015 10 SCE Distribution System Investments Distribution Trends • Aging system reaching equilibrium replacement rate • 2015 GRC includes 94% increase in infrastructure replacement • Distribution spending will be sustained by: - Public safety and reliability - Distribution Resources Plan (DRP) - Grid readiness - Electric vehicle charging and storage - State environmental policy Load Growth New Service Connections Infrastructure Replacement General Plant Other 2015 – 2017 GRC Final Decision Expenditures for Distribution Assets1 $8.5 Billion 1. Preliminary analysis of GRC final decision and subject to change; excludes DRP capital spending

November 19, 2015 11 • Revenues based on GRC final decision • Weighted-average 2015 rate base of $23.0 billion (see Rate Base Forecast) • Energy efficiency earnings of $0.05 per share • Includes proposed ex-parte penalty • Includes disallowance of $10 million solar termination payment – ($0.02) per share • Authorized capital structure – 48% equity; 10.45% CPUC and FERC ROE • No change in tax policy • 325.8 million common shares outstanding Key Assumptions (core) $3.54 3.54 3.82 $3.82 (0.15) 0.43 SCE 2015 EPS from Rate Base Forecast 2015 SCE Variances EIX Parent & Other 2015 Core EIX EPS Midpoint Guidance 2015 Core and Basic Earnings Guidance 1. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. Non-core items as of October 27, 2015 include $0.15 per share of non-core items recorded for the nine months ended September 30, 2015. Non-core items as of November 9, 2015 also include ($1.17) per share write off of regulatory asset and $0.04 per share of NEIL settlement recovery 3. AFUDC benefits net certain SCE costs (such as philanthropy, executive compensation, and certain other allocated costs) not authorized by GRC proposed decision As of October 27, 2015 As of November 9, 2015 Low Mid High Low Mid High SCE $3.97 $3.97 EIX Parent & Other (0.15) (0.15) EIX Core EPS1 $3.77 $3.82 $3.87 $3.77 $3.82 $3.87 Non-Core Items2 0.15 0.15 0.15 (0.98) (0.98) (0.98) EIX Basic EPS $3.92 $3.97 $4.02 $2.79 $2.84 $2.89 • Change in uncertain tax positions - $0.31 • AFUDC net benefits3 - $0.07 • Energy efficiency - $0.05 • Severance –($0.03) • Ex-parte penalty & Other - $0.03 ($ per share) 2015 Earnings Guidance Key Assumptions (non-core) • Includes $382 million write off of tax repair regulatory asset • Includes NEIL settlement recovery

November 19, 2015 12 SCE Growth Drivers Beyond 2017 Infrastructure Reliability Investment • Sustained level of infrastructure investment required until equilibrium replacement rates are achieved and then maintained - includes underground cable, poles, switches, and transformers1 Distribution Resources Plan • Accelerate automation and control technology at optimal locations to manage two-way power flows with more dynamic voltage control • DRP required under AB 327 to identify optimal locations, additional spending, and barriers to deploying distributed energy resources – filed July 1, 2015 Transmission • California ISO 2013-2014 Transmission Plan2 - approved Mesa Loop-in Project (system reliability post-SONGS and renewables integration) with target in-service date of December 31, 2020 • West of Devers (2019-2020) incorporated from prior Transmission Plans in service beyond 2017 Energy Storage • 290 MW utility owned investment opportunity 2015-2024 SCE Charge Ready Program • Targets approximately 1/3 of needed charging infrastructure Other California Public Policy Requirements • Transportation electrification • 50% renewables mandate by 2030 1. Source: A.13-11-0032015 GRC – SCE-01 Policy testimony; equilibrium replacement rate defined as equipment population divided by mean time to failure for type of equipment 2. Approved by the California ISO Board of Governors March 20, 2014

November 19, 2015 13 Distribution Grid of the Future One-Way Electricity Flow • System designed to generate electricity from large central plant • Very few distributed energy resources • Voltage relatively simple to maintain • Limited situational awareness and visualization tools for grid operators Renewable Generation Mandates Subsidized Residential Solar Lack of Electric Vehicle Charging Infrastructure Variable, Two-Way Electricity Flow • Distribution system at the center of the grid • System designed to serve variable resources and customer demand • Digital monitoring and control devices and advanced communications systems to manage two-way flows • Improved data management and grid operations with cyber mitigation Maximize Distributed Resources and Electric Vehicle Adoption • Distribution grid infrastructure design supports customer choice and greater resiliency Current State Future State

November 19, 2015 14 Future state based on evolving energy landscape More automation enhances interaction of grid with customer devices & DER. Sophisticated automation schemes now possible Prediction of DER performance facilitates increasing renewables & two- way power flow Software tools for real time state estimation, grid simulation & optimization Bolstered telecommunications supports increased telemetry and faster remote response 1 2 3 3 1 2 2 1 1 1 4 4 4 4 21st Century Grid Highlights

November 19, 2015 15 AB 327 required IOU submissions of Distribution Resources Plans (DRP) on July 1, 2015 to integrate increasing penetration of Distributed Energy Resources (DERs). Key provisions of the DRP filing include: • Methodology/tools for identifying optimal locations for DERs (includes distributed generation, energy storage, electric vehicle charging, energy efficiency and demand response) • Enhance the electric system’s capability to integrate more DERs at the distribution level through modernization of system planning tools, design and operations • Technology recommendations (information technology, communications, system planning, voltage and frequency controls, etc.) SCE’s DRP includes a conceptual capital plan • Estimated scope of work, technology roadmap, timeline, and capital and expense cost estimates • Incremental to traditional general rate case expenditures; implementation recommendations proposed to be integrated into future general rate cases beginning with the 2018 filing • Overall capital spending expected to be at least in the range of current forecast levels, although could result in higher spending pending CPUC approval in future GRCs SCE Distribution Resources Plan

November 19, 2015 16 2015 - 2017 2018 - 2020 2021 + Implement foundational information technology, communication systems, and system planning tools; begin grid reinforcement work Expand automation and improve communications and control with Distributed Energy Resources; continue grid reinforcement work Continue grid modernization, maximize benefits of Distributed Energy Resources and continue integrating into planning and operationsT e c h n o l o g y E x p e c t e d R e s u l t G R C C y c l e Prepare organization and workforce to execute incremental work Ramp up resources and develop talent pipeline Compliance, safety, and reliability; preparation for future grid state New business opportunities enabled; full deployment of grid modernization Prepare grid management systems to handle increased DER and support more grid transactions P e o p l e a n d P r oces s SCE’s July 1, 2015 DRP supports the Commission’s proposed phased approach, which would be implemented over future General Rate Case (GRC) cycles SCE Grid Modernization Road Map

November 19, 2015 17 SCE DRP Capital Expenditure Estimates Time Period Capital Expenditures CPUC Approval Mechanism 2015-2017 Distribution Automation $40-70 million • Proposed memorandum account to record associated revenue requirement until expenditures are authorized by CPUC Substation Automation $30-60 million Communications Systems $7-15 million Technology Platforms and Applications $130-200 million Grid Reinforcement $140-215 million Total $347-560 million 2018-2020 Distribution Automation $185-320 million • Request recovery in 2018 GRCSubstation Automation $185-320 million Communications Systems $270-470 million Technology Platforms and Applications $215-375 million Grid Reinforcement $550-1,100 million Total $1,405-2,585 million SCE anticipates capital spending to continue at least in the range of current forecast levels, although could result in higher spending pending CPUC approval in future GRCs Note: Totals for 2015-2017 and 2018-2020 include O&M spending of $20-30 million and $60-100 million, respectively

November 19, 2015 18 Energy Storage • AB2514 directed CPUC to establish procurement targets and policies for storage • CPUC Energy Storage OIR (R.10-12-007) established: – 1,325 MW target for IOUs by 2024 (580 MW SCE share; spread as biennial targets during 2014-2020) – Three categories: transmission (53%), distribution (32%), customer-sited (15%) – Limited flexibility to transfer across categories – Utility ownership limited to 50% of total target (290 MW SCE share) – Broad range of technologies as defined in AB2514, excluding large hydro (>50 MW) • Standalone storage RFO launched December 2014 – Existing storage and prior RFO storage counts for ~74MW of SCE’s 90 MW target in 2014 – Contracts from 2014 procurement cycle will be submitted for CPUC approval in December 2015 • Tehachapi Storage Project • Irvine Smart Grid Demonstration Projects • Large Energy Storage Test Apparatus • Discovery Science Center • Catalina Island Battery System • Vehicle-to-Grid Program – LA Air Force Base • Self-Generation Incentive Program • Permanent Load Shifting Program 50 30 10 0 50 100 150 Transmission Distribution Customer M W SCE 2015 Storage Portfolio Approved to count toward targets Expected to be approved following filing (March 2016) Currently above targets. May be eligible if flexibility rules are modified 2014 Procurement Target SCE’s energy storage investment opportunities will focus on distribution grid projects and will be integrated into future capital expenditure requests

November 19, 2015 19 SCE Charge Ready Program • Electric vehicle Charge Ready Program application submitted to CPUC (A.14-10-014) in October 2014 • Pro-active, two-phased program over five years to support installation of up to 30,000 EV charging stations to be included in rate base – Phase 1: pilot program for 1,500 chargers and market education program (2015 – 2016) – Phase 2: 28,500 chargers (2016 – 2020) • On July 9, 2015, SCE and 15 other parties filed a settlement agreement on Phase 1 which is awaiting CPUC approval − $225 million total rate base opportunity if Phase 2 follows settled approach • Addresses approximately 1/3 of forecast non- single family home charging demand in SCE territory in 2020 SCE’s electric vehicle Charge Ready Program supports Governor Brown’s 2012 zero-emission vehicle Executive Order – 1.5 million EVs by 2025 • Level 1 (110V) and Level 2 (240V) chargers with Demand Response capability • As a general rule, 10 chargers per site minimum • Participants own / operate / maintain chargers • Capital cost per charging station: $11,400

November 19, 2015 20 SCE Key Regulatory Proceedings Proceeding Description Next Steps Key SCE Proceedings 2015 GRC Application (A.13‐11‐003) Rate setting for CPUC 3‐year cycle 2015 – 17 Final decision received November 5, 2015 Cost of Capital Application Capital structure and return on equity Settlement for 1 year extension pending CPUC approval Distribution Resources Plan OIR (R.14‐08‐013) Grid investments to integrate distributed energy resources SCE plan submitted July 1, 2015; CPUC schedule pending Rate Design OIR (R.12‐06‐013) Tiers, fixed charges, time of use (Phase 1); Net metering tariff (R.14‐01‐002) Phase 1 decision issued July 3, 2015; NEM final decision expected in 2015 SONGS OII (I.12‐10‐013) Motions on sanctions/reopening the settlement and Application For Rehearing (AFR) pending Decision on motions and AFR; OII open through November 26, 2015 but can be extended Key FERC Proceedings FERC Formula Rates Transmission rate setting with annual updates ROE moratorium expired July 1, 2015; annual update due December 2015; settlement in place through December 2017 Other Proceedings 2012 LTPP Tracks 1 & 4 RFO (D.13‐02‐015) Local capacity/preferred resources to replace SONGS and once through cooling plants 2,221 MW, including 262 MW storage, submitted for PUC approval November 2014 Energy Storage RFO Solicitation for 16.3 MW launched December 2014 Short list notification May 15, 2015; final selection September 14, 2015 Energy Resource Recovery Account (ERRA) Annual forecast and review of fuel and purchased power costs 2015 settlement for no increase filed July 2015; 2016 forecast submitted May 2015

November 19, 2015 21 CPUC and FERC Cost of Capital 3 4 5 6 7 10/1/12 10/1/13 10/1/14 10/1/15 10/1/16 R a t e ( % ) CPUC Adjustment Mechanism Moody’s Baa Utility Index Spot Rate Moving Average (10/1/14 – 9/30/15) = 4.82% 100 basis point +/- Deadband Starting Value – 5.00% CPUC – 48% common equity and Return on Equity (ROE) adjustment mechanism has been extended through 2016 • Weighted average authorized cost of capital – 7.90% • ROE adjustment based on 12-month average of Moody’s Baa utility bond rates, measured from Oct. 1 to Sept. 30 • If index exceeds 100 bps deadband from starting index value, authorized ROE changes by half the difference • Starting index value based on trailing 12 months of Moody’s Baa index as of September 30, 2012 – 5.00% • Settlement pending CPUC approval for 2017 Cost of Capital – adjustment mechanism continues in the interim FERC – comparable to CPUC 10.45% ROE • Includes 9.30% base + 50 bps CAISO participation plus project incentives • Moratorium on filing ROE changes expired July 1, 2015 • FERC Formula recovery mechanism in effect through December 31, 2017

November 19, 2015 22 Residential Rate Design OIR • CPUC Order Instituting Ratemaking R.12-06-013 comprehensively reviewed residential rate structure including a future transition to time of use rates • July 2015 CPUC Decision D.15-07-001 includes: - Transition to 2 tiered rates by 2019 - “Super User Electric Surcharge” for usage 400% above baseline (~4% of current residential load) - Continue fixed charge at $0.94/month, but rejected requests for increased fixed charges allowing IOUs to re-file fixed charge requests as early as 2018. - Minimum bills up to $10/month which applies to delivery revenue only • Net Energy Metering (R.14-07-002): successor tariff due Q4 2015 Current Rates – October 2015 18.2¢ 40.8¢ 100% 101‐400% >400% 23.3¢ Usage Level (% of Baseline) ¢ / k W h Future Rates - 2019 Usage Level (% of Baseline) 15.1¢ 24.3¢ 30.2¢ 100% 101‐ 130% 131‐ 200% 200‐400% >400% 20.9¢ ¢ / k W h Fixed Charge: $0.94/month Minimum Bill: $10.00/month Fixed Charge: $0.94/month Minimum Bill: $10.00/month Note: Graphs not to scale. 2019 rate levels are based on current revenue requirements

November 19, 2015 23 SCE Residential Net Metering Rate Structure 7¢ 24¢17¢ 0 5 10 15 20 25 30 ¢ / k W h Solar Subsidies (Illustrative) Avoided Generation (excludes RPS Premium) Subsidy Paid by Other Ratepayers Equivalent Solar Offset Current rate design results in residential solar customers receiving a subsidy funded by all other non-solar customers SCE’s Rate Developments: • Residential solar customer generation offsets total retail rate via Net Energy Metering (NEM) structure • Through tiered rate flattening, Residential Rate OIR decision will reduce subsidy paid by non-solar customers by about 20% • 20-year NEM grandfathering at retail rate for installations up to 5% cap (2,240 MW for SCE) interconnected before July 2017 • On August 3rd, SCE (and other parties) filed rate proposals with the CPUC that are more reflective of distributed energy systems’ total costs and benefits SCE Net Energy Metering Statistics (End of August): • 139,456 combined residential and non-residential projects – 1,098 MW installed (of 2,240 MW cap) – 99.7% solar – 135,619 residential – 691.6 MW – 3,837 non-residential – 406.3 MW • Approximately 1,969,517 MWh / year generated

November 19, 2015 24 On August 3rd, SCE filed its proposal for a successor to the current NEM tariff and alternative offerings to grow residential distributed generation in disadvantaged communities SCE’s proposal includes the following key elements: • Elimination of netting and decoupling of exported energy from retail rates • Energy charges ($/kWh) billed at full retail rates for all energy imported from SCE • Energy credits for exports, paid at Export Compensation Rate (ECR) of 8¢/kWh - 7¢/kWh to account for levelized utility avoided costs (CPUC E3 Public Tool estimate) - 1¢/kWh to account for renewable energy credit value of exported energy • Grid Access Charge (GAC) of $3/kW-month based on DG system capacity size • Comprised of charges for utilities’ fixed T&D costs and non-bypassable costs • Alternatives to the Successor Tariff designed to grow renewable DG among residential customers in disadvantaged communities, including incentive programs, a marketing/outreach campaign, and a proposal for community solar NEM Successor Tariff Proposal NEM Successor Tariff decision is expected by the end of 2015

November 19, 2015 25 SCE Operational Excellence Top Quartile • Safety • Cost efficiency • Reliability • Customer service Optimize • Capital productivity • Purchased power cost High performing, continuous improvement culture Defining Excellence Measuring Excellence • Employee and public safety metrics • System reliability (SAIDI, SAIFI, MAIFI) • J.D. Power customer satisfaction • O&M cost per customer • Reduce system rate growth with O&M / purchased power cost reductions Ongoing Operational Excellence Efforts

November 19, 2015 26 EIX Annual Dividends Per Share $0.80 $1.00 $1.08 $1.16 $1.22 $1.24 $1.26 $1.28 $1.30 $1.35 $1.42 $1.67 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Note: See use of Non-GAAP Financial Measures in Appendix Eleven Years of Dividend Growth EIX targets a payout ratio of 45 – 55% of SCE core earnings and plans to return to target payout ratio in steps, over time

November 19, 2015 27 Appendix

November 19, 2015 28 On November 5, 2015, the CPUC issued a final decision supportive of SCE strategy to increase infrastructure reliability and safety investment while mitigating customer rate impacts through productivity and operating efficiency • 2015 authorized revenue requirement of $5.182 billion - $330 million reduction from SCE’s request and $23 million increase from proposed decision - $451 million reduction from presently authorized base rates • 2015 capital spending reduced $335 million from SCE’s request, consistent with the proposed decision • 2015 rate base of $17.376 billion, $800 million below SCE’s request and $91 million below proposed decision Year SCE Request (Update Testimony 5/11/15 - Table II-4) Proposed Decision 9/18/15 Difference (Request to PD) Final Decision 11/5/15 Difference (PD to FD) Base Revenue Requirement 2015 $5.512 $5.159 ($0.353) $5.182 $0.023 2016 $5.748 $5.429 ($0.319) $5.391 ($0.038) 2017 $6.067 $5.704 ($0.363) $5.663 ($0.041) CPUC Rate Base 2015 $18.176 $17.467 ($0.709) $17.376 ($0.091) 2016 $19.933 $19.229 ($0.704) $18.714 ($0.515)1 2017 $21.603 $20.725 ($0.878) $20.176 ($0.549)1 ($ billions) 2015 General Rate Case Final Decision 1. The ALJ’s proposed decision (PD) did not include the rate base offset for tax repair deductions in 2016 and 2017. The final decision corrects this error. The PD error was already considered in the company’s October 28th rate base forecast. For accounting implications, see “Tax Repair Ratemaking and Accounting”

November 19, 2015 29 Rate Base • Adjustment revised to amortize over 27 years - see “Tax Repair Ratemaking and Accounting” • $180 million exclusion of customer deposits – no change • $73 million pole loading reduction – no change Expenses • $71 million incentive compensation reduction – reduced by $10 million • $10 million commercial solar program disallowance – no change Under Review • Regulatory and tax implications • Memorandum accounts Resolution of GRC Open Items Proposed Decision Final Decision Rate Base • $344 million tax repair adjustment • $180 million exclusion of customer deposits • $73 million pole loading reduction Expenses • $81 million incentive compensation reduction • $10 million commercial solar program disallowance

November 19, 2015 30 Tax Repair Ratemaking and Accounting Tax Repair Ratemaking • In SCE’s 2015 GRC final decision, the CPUC adopted a rate base offset associated with forecasted tax repair deductions during 2012-2014 – In 2015, the CPUC rate base offset is $324 million1 and amortizes on a straight line basis over 27 years • SCE disagrees with the CPUC’s actions and is concerned that the rate base offset approach may be retroactive ratemaking. SCE will also confirm with the IRS that the offset approach is not a normalization violation Tax Repair Accounting • SCE’s regulatory assets include $382 million for recovery of deferred taxes related to incremental repair deductions for 2012-2014 • Based on the decision, it is no longer probable that SCE will recover the regulatory asset. Therefore, SCE will write off this amount in the fourth quarter of 2015 (treated as non-core) • Because the ”rate base offset” will be implemented through the regulatory asset write- off, no “rate base offset” is needed for future earning forecasts 1. The CPUC final decision refers to a $344 million rate base adjustment of which $324 million represents the CPUC jurisdictional rate base

November 19, 2015 31 SCE 2014 Bundled Revenue Requirement Note: Rates in effect as of July 7, 2014, based on forecast. Represents bundled service which excludes Direct Access customers that do not receive generation services SCE Systemwide Average Rate History (¢/kWh) 2010 2011 2012 2013 2014 14.3 14.1 14.3 15.9 16.7 Fuel & Purchased Power (41%) Distribution (32%) Transmission (6%) Generation (17%) Other (4%) 2014 Bundled Revenue Requirement $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond Charge 5,071 6.9 Distribution – poles, wires, substations, service centers; Edison SmartConnect® 3,867 5.3 Generation – utility owned generation investment and O&M 2,048 2.8 Transmission – greater than 220kV 735 1.0 Other – CPUC and legislative public purpose programs, system reliability investments, nuclear decommissioning 539 0.7 Total Bundled Revenue Requirement ($millions) $12,260  Bundled kWh (millions) 73,249 = Bundled Systemwide Average Rate (¢/kWh) 16.7¢

November 19, 2015 32 (0.3¢) (0.7¢) (1.2¢) 0.3¢ 0.4¢ 0.2¢5.30 4.00 Current 2015 SAR 2015 ERRA Settlement 2015 GRC Expiration of Prior Refunds Other CPUC 2016 FERC 2016 ERRA Changes March 2016 SAR 2016 Forecast System Average Rate SCE’s system average rate is expected to decline from 16.3¢/kWh to 15.0¢/kWh in early 2016, an 8% decrease (¢/kWh) 1. Includes public purpose, 2016 SONGS revenue requirement and other 1 16. ¢ 15.0¢

November 19, 2015 33 12.9 16.4 US Average SCE 27% Higher • SCE’s residential rates are above national average due, in part, to a cleaner fuel mix – cost for renewables are higher than high carbon sources • Average monthly residential bills are lower than national average – higher rate levels offset by lower usage – 42% lower SCE residential customer usage than national average, from mild climate and higher energy efficiency building standards • Public policy mandates (33% RPS, AB32 GHG, Once-through Cooling) and electric system requirements will drive rates and bills higher 2014 Average Residential Rates (¢/kWh) 2014 Average Residential Bills ($ per Month) Key Factors ¢ ¢ SCE’s average residential rates are above national average, but residential bills are below national average due to lower energy usage $127 $94 US Average SCE 26% Lower Source: EIA's Form 826 Data Monthly Electric Utility Sales and Revenue Data for 2014 SCE Rates and Bills Comparison

November 19, 2015 34 SCE Customer Demand Trends Kilowatt-Hour Sales (millions of kWh) Residential Commercial Industrial Public authorities Agricultural and other Subtotal Resale Total Kilowatt-Hour Sales Customers Residential Commercial Industrial Public authorities Agricultural Railroads and railways Interdepartmental Total Number of Customers Number of New Connections Area Peak Demand (MW) 2012 30,563 40,541 8,504 5,196 1,676 86,480 1,735 88,215 4,321,171 549,855 10,922 46,493 21,917 83 24 4,950,465 22,866 21,996 2011 29,631 39,622 8,490 5,206 1,318 84,267 3,071 87,338 4,301,969 546,936 11,370 46,684 22,086 82 22 4,929,149 19,829 22,443 2013 29,889 40,649 8,472 5,012 1,885 85,907 1,490 87,397 4,344,429 554,592 10,584 46,323 21,679 99 23 4,977,729 27,370 22,534 Note: See 2014 Edison International Financial and Statistical Reports for further information 2014 30,115 42,127 8,417 4,990 2,025 87,674 1,312 88,986 4,368,897 557,957 10,782 46,234 21,404 105 22 5,005,401 29,879 23,055 YTD 2015 22,924 32,344 5,840 3,639 1,590 66,337 697 67,034 4,387,945 560,693 10,899 46,346 21,366 119 22 5,027,390 22,957 23,079

November 19, 2015 35 (Southern California) Source: Energy Information Administration, October 2015. Data is for SP-15 Nodes Wholesale Electricity Prices, May 2014-Sep 2015 $0 $10 $20 $30 $40 $50 $60 $70 $80 May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep

November 19, 2015 36 California’s Energy Policy • On October 7, 2015, Governor Brown signed SB 350, which requires that 50 percent of energy sales to customers come from renewable power and a doubling of energy efficiency in existing buildings for California by 2030 - Also requires Transportation Electrification investments and Integrated Resources Planning • In order to meet the 33% RPS requirement by 2020, SCE will need to increase its renewable purchases by 7.4 billion kWh, or 42% Renewables Electric Vehicles Energy Efficiency Legislative Action • Emissions targets met through optimization of renewables, transportation electrification, energy efficiency Regulatory Approach: Utility participation through infrastructure investment • SCE Charge Ready application • Distribution grid investments to meet EV impact Continuation of utility programs and earnings incentive mechanism • SCE 2015 program budget: $333 million • $0.05 per share 2015 earnings potential Utility Role Solar 15% Small Hydro 2% Geothermal 39% Wind 42% Actual 2014 Renewable Resources: 23.4% of SCE’s portfolio Biomass 2%

November 19, 2015 37 • Assembly Bill 32 (2006) – reduces State greenhouse gas (GHG) emissions to 1990 levels by 2020 (~16% reduction) • Cap and trade program basics: – State-wide cap in 2013 – decreases over time – Compliance met through allowances, offsets, or emissions reductions – Excess allowances sold, or “banked” for future use – January 2014 – merger with Quebec cap and trade program • SCE received 31.6 million 2014 allowances vs. a financial exposure to only 21.8 million metric tons of GHG emissions that same year • Allowances sold into quarterly auction and bought back for compliance – SB 1018 (2012) – auction revenues used for rate relief for residential (~93%), small business, and large industrial customers AB32 Emissions Reduction Programs Cap & Trade 22% Other 23% Low Carbon Fuel Standard 19% RPS 14% Energy Efficiency 15% High GWP Gases 7% California Cap and Trade Program

November 19, 2015 38 Energy efficiency programs updated for 2013 – 2015 • 2015 budget of $333 million • Savings targets of 983 GWh and 160.1 MW for 2015 – Reduced goals reflect CPUC-identified potential for energy efficiency Energy efficiency earnings incentive mechanism modified • CPUC approved new incentive mechanism for 2013 – 2015 activities comprised of performance rewards and management fees SCE Energy Efficiency Earnings Summary Program Year Total Requested Received Pending CPUC Approval 2010 $15.1 million $0.03/share $15.1 million $0.03/share (2012) 2011 $18.6 million $0.04/share $13.6 million $0.03/share (2013) $5.0 million $0.01/share 2012 $16.2 million $0.03/share $10.8 million $0.02/share (2013) $1.2 million $0.00/share 2013 (Part 1) $14.2 million $0.03/share $10.8 million $0.02/share (2014) 2013 (Part 2) $10.5 million $0.03/share Expected in 2015 2014 (Part 1) $12.1 million $0.03/share Expected in 2015 2014 (Part 2) $14.4 million $0.04/share Expected in 2016 SCE Energy Efficiency Programs Note: Additional program year 2013 award request, and request for $5.0 million and $1.2 million currently pending, expected to be submitted in 2015

November 19, 2015 39 EIX is Responding to Industry Change • Public policy prioritizing environmental sustainability • Innovation facilitating conservation and self-generation • Regulation supporting new forms of competition • Flattening domestic demand for electricity • Grid of the future will be more complex and sophisticated to support increasing use of distributed resources and transportation electrification SCE Strategy • Invest in, build, and operate the next generation electric grid • Operational and service excellence • Enable California public policies EIX Competitive Strategy • Small, targeted investments in emerging technologies and markets to follow changes in the industry and better exploit opportunities as they arise – Commercial and industrial distributed generation – Energy optimization – Energy efficiency and software – Residential solar industry financial services and software – Electric transportation Long-Term Industry Trends Strategy

November 19, 2015 40 • Create energy services that help simplify and optimize energy needs for commercial & industrial customers: – Help customers better value energy optimization, paving the way for greater third party energy services – Help customers manage through potential technological / regulatory changes Changing Customer Needs Evolving customer needs and uncertainty around changing technologies and regulation create a business opportunity for a trusted advisor role The Opportunity: Trusted Advisor Edison Energy Focus: Commercial & Industrial

November 19, 2015 41 On June 10th, eight electric utilities and energy companies announced a MOU to pursue the development of Grid Assurance, a limited liability company that plans to offer subscribers cost- effective solutions for enhancing grid resiliency and protecting customers from prolonged transmission outages • Grid Assurance is intended to address potential high impact events on the bulk transmission systems: - Entity will own critical equipment with long manufacturing lead times to account for risk beyond what is covered by “operational spares” (e.g., BES transformers, breakers, etc.) - Entity will provide secure, off-site storage in strategic locations, and support the delivery of equipment transportation and logistics services - Subscribers will pay a cost-of-service based subscription fee for access to inventory and will have rights to call upon inventory following a “Qualifying Event” such as physical attacks, electromagnetic pulses, solar storms, cyberattacks, earthquakes and severe weather events - Regulatory construct will provide cost certainty and cost recovery similar to FERC formula rates for transmission assets - Subscription to the sparing service will be available to all transmission owning entities • Contingent on regulatory approvals, Grid Assurance is expected to begin accepting subscribers and identifying inventory in 2016 Edison Transmission is one of the eight companies pursuing Grid Assurance Grid AssuranceTM Overview

November 19, 2015 42 Q3 2015 Q3 2014 Variance Core Earnings Per Share (EPS)1 SCE $1.19 $1.54 ($0.35) EIX Parent & Other (0.03) (0.02) (0.01) Core EPS1 $1.16 $1.52 ($0.36) Non-Core Items2 SCE $ – $ – $ – EIX Parent & Other – – – Discontinued Operations 0.13 (0.05) 0.18 Total Non-Core $0.13 ($0.05) $0.18 Basic EPS $1.29 $1.47 ($0.18) Diluted EPS $1.28 $1.46 ($0.18) SCE Key Core EPS Drivers Lower revenue3 ($0.40) - Lower GRC revenue – tax repairs4 (0.20) - Lower GRC revenue – other4 (0.22) - FERC revenue and other 0.02 Higher O&M (0.03) Higher depreciation (0.02) Lower net financing costs 0.02 Income taxes 0.08 - Higher authorized tax repair deductions4 0.20 - 2014 incremental tax repair deductions (0.11) - Lower tax benefits (0.01) Total ($0.35) Third Quarter Earnings Summary 1. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. Refer to “Management Overview” in the September 30, 2015 Form 10-Q for discussion of non-core items 3. Excludes San Onofre revenue of $0.09, which was offset by amortization of regulatory assets of $(0.13), interest expense of $(0.01), O&M of $0.04, income taxes of $0.02 and other of $(0.01) 4. During the third quarter of 2015, SCE recorded revenue subject to refund of $233 million $(0.42). Higher authorized tax repair deductions were $0.20 per share which is reflected in the revenue subject to refund. Lower operating costs and other income tax benefits were reflected in the 2015 GRC thereby reducing authorized revenue as compared to 2014 EIX Key Core EPS Drivers Lower income from Edison Capital ($0.02) Income taxes and expenses 0.01 Total ($0.01)

November 19, 2015 43 $1.16 (0.20) (0.03) (0.02) (0.12) (0.01) 0.02 $1.52 Q3 2014 Core EPS Lower Revenue Higher O&M Higher Depreciation Lower Net Financing Costs Higher Income Taxes EIX Parent & Other Q3 2015 Core EPS Key Drivers of Q3 2015 Core EPS Lower revenues reflect 2015 GRC Proposed Decision 1 1 Note: See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 1. Lower GRC revenue – tax repairs of $(0.20) are netted against higher authorized tax repair deductions of $0.20 on this graph; these items do not have an earnings impact ($ per share)

November 19, 2015 44 YTD 2015 YTD 2014 Variance Core Earnings Per Share (EPS)1 SCE $3.31 $3.58 ($0.27) EIX Parent & Other (0.09) (0.08) ($0.01) Core EPS1 $3.22 $3.50 ($0.28) Non-Core Items2 SCE $ – ($0.29) $0.29 EIX Parent & Other 0.02 – 0.02 Discontinued Operations 0.13 0.45 (0.32) Total Non-Core $0.15 $0.16 ($0.01) Basic EPS $3.37 $3.66 ($0.29) Diluted EPS $3.34 $3.62 ($0.28) YTD 2015 Earnings Summary 1. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. Refer to “Management Overview” in the September 30, 2015 Form 10-Q for discussion of non-core items 3. Excludes San Onofre revenue of $0.15, which was offset by amortization of regulatory assets of $(0.25), interest expense of $(0.02), O&M of $0.11, income taxes of $0.02 and other of $(0.01) 4. During the nine months of 2015, SCE recorded revenue subject to refund of $318 million $(0.58). Higher authorized tax repair deductions were $0.36 per share which is reflected in the revenue subject to refund. Lower operating costs and other income tax benefits were reflected in the 2015 GRC thereby reducing authorized revenue as compared to 2014 5. Includes San Onofre impact of $(0.01) primarily due to property and sales tax refund of $0.02 related to replacement steam generators for the nine months ended September 30, 2014 SCE Key Core EPS Drivers Lower revenue3 ($0.43) - Lower GRC revenue – tax repairs4 (0.36) - Lower GRC revenue – other4 (0.22) - FERC revenue and other 0.15 Higher O&M (0.02) Higher depreciation (0.11) Lower net financing costs 0.08 Income taxes 0.28 - Higher authorized tax repair deductions4 0.36 - 2014 incremental tax repair deductions (0.26) - 2015 change in uncertain tax positions 0.31 - 2014 change in uncertain tax positions (0.09) - Lower tax benefits (0.04) Other items (0.07) - Property taxes and other5 (0.04) - Generator settlements (0.03) Total ($0.27) EIX Key Core EPS Drivers Income taxes and expenses ($0.01) Total ($0.01)

November 19, 2015 45 Key Drivers of YTD 2015 Core EPS $3.22 (0.07) (0.02) (0.11) (0.08) (0.04) (0.03) (0.01) 0.08 $3.50 YTD 2014 Core EPS Lower Revenue Higher O&M Higher Depreciation Lower Net Financing Costs Higher Income Taxes Property Taxes and Other Generator Settlements EIX Parent & Other YTD 2015 Core EPS Note: See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 1. Lower GRC revenue – tax repairs of $(0.36) are netted against higher authorized tax repair deductions of $0.36 on this graph; these items do not have an earnings impact 1 1 ($ per share)

November 19, 2015 46 $6,602 — 2,348 1,622 307 575 4,852 1,750 (519) 48 1,279 279 1,000 100 $900 $5,960 4,891 1,068 — — — 5,959 1 (1) — — — — — $— $6,831 — 2,106 1,720 318 163 4,307 2,524 (528) 43 2,039 474 1,565 112 $1,453 $6,549 5,593 951 — — — 6,544 5 (5) — — — — — $— $13,380 5,593 3,057 1,720 318 163 10,851 2,529 (533) 43 2,039 474 1,565 112 $1,453 $1,525 (72) $1,453 $12,562 4,891 3,416 1,622 307 575 10,811 1,751 (520) 48 1,279 279 1,000 100 $900 $1,265 (365) $900 SCE Results of Operations • Utility earning activities – revenue authorized by CPUC and FERC to provide reasonable cost recovery and return on investment • Utility cost-recovery activities – CPUC- and FERC-authorized balancing accounts to recover specific project or program costs, subject to reasonableness review or compliance with upfront standards Utility Earning Activities Utility Cost- Recovery Activities Total Consolidated 2014 Utility Earning Activities Utility Cost- Recovery Activities Total Consolidated 2013 Operating revenue Purchased power and fuel Operation and maintenance Depreciation, decommissioning and amortization Property and other taxes Impairment and other charges Total operating expenses Operating income Interest expense Other income and expenses Income before income taxes Income tax expense Net income Preferred and preference stock dividend requirements Net income available for common stock Core earnings Non-core earnings Total SCE GAAP earnings Note: See Use of Non-GAAP Financial Measures in Appendix ($ millions)

November 19, 2015 47 Earnings Non-GAAP Reconciliations Reconciliation of EIX Core Earnings to EIX GAAP Earnings Earnings Attributable to Edison International Core Earnings SCE EIX Parent & Other Core Earnings Non-Core Items SCE EIX Parent & Other Discontinued operations Total Non-Core Basic Earnings Q3 2014 $503 (7) $496 $ − – (16) $(16) $480 Q3 2015 $389 (12) $377 $ – 1 43 $44 $421 Note: See Use of Non-GAAP Financial Measures in Appendix YTD 2014 $1,168 (26) $1,142 $(96) – 146 $50 $1,192 YTD 2015 $1,079 (30) $1,049 $ – 7 43 $50 $1,099 ($ millions)

November 19, 2015 48 Earnings Per Share Non-GAAP Reconciliations Reconciliation of EIX Core Earnings Per Share to EIX GAAP Earnings Per Share 1. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix of the October 2015 Business Update 2. Refer to “Management Overview” in the September 30, 2015 Form 10-Q for discussion of non-core items ($ per share) Q3 2015 Q3 2014 YTD 2015 YTD 2014 Core Earnings Per Share (EPS)1 SCE $1.19 $1.54 $3.31 $3.58 EIX Parent & Other (0.03) (0.02) (0.09) (0.08) Core EPS1 $1.16 $1.52 $3.22 $3.50 Non-Core Items2 SCE $ – $ – $ – ($0.29) EIX Parent & Other – – 0.02 – Discontinued Operations 0.13 (0.05) 0.13 0.45 Total Non-Core $0.13 ($0.05) $0.15 $0.16 Basic EPS $1.29 $1.47 $3.37 $3.66 Diluted EPS $1.28 $1.46 $3.34 $3.62

November 19, 2015 49 SCE Core EPS Non-GAAP Reconciliations Earnings Per Share Attributable to SCE Core EPS Non-Core Items Tax settlement Health care legislation Regulatory and tax items Impairment and other charges Total Non-Core Items Basic EPS Reconciliation of SCE Core Earnings Per Share to SCE Basic Earnings Per Share 2009 $2.68 0.94 — 0.14 — 1.08 $3.76 2010 $3.01 0.30 (0.12) — — 0.18 $3.19 CAGR 12% 4% 2011 $3.33 — — — — — $3.33 2012 $4.10 — — 0.71 — 0.71 $4.81 2013 $3.88 — — — (1.12) (1.12) $2.76 Note: See Use of Non-GAAP Financial Measures in Appendix 2014 $4.68 — — — (0.22) (0.22) $4.46

November 19, 2015 50 Use of Non-GAAP Financial Measures Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings are also used when communicating with investors and analysts regarding Edison International's earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (or losses) are defined as earnings or losses attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including sale of certain assets, and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings. A reconciliation of Non-GAAP information to GAAP information is included either on the slide where the information appears or on another slide referenced in this presentation. EIX Investor Relations Contact Scott Cunningham, Vice President (626) 302‐2540 scott.cunningham@edisonintl.com Allison Bahen, Senior Manager (626) 302‐5493 allison.bahen@edisonintl.com