EX-99.2 3 eixq32013earningstelecon.htm EIX 3RD QTR 2013 FINANCIAL TELECONFERENCE PRESENTATION DATED 10/29/2013
Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 0 Third Quarter 2013 Financial Teleconference

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 1 Statements contained in this presentation about future performance, including, without limitation, operating results, asset and rate base growth, capital expenditures, San Onofre Nuclear Generating Station (SONGS), EME bankruptcy, 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 2012 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. Forward-Looking Statements

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 2 Third Quarter Earnings Summary Q3 2013 Q3 2012 Variance Core EPS1 SCE $1.46 $1.11 $0.35 EIX Parent & Other (0.04) (0.11) 0.07 Core EPS1 $1.42 $1.00 $0.42 Non-Core Items SCE $— $— $— EIX Parent & Other Continuing Operations — 0.09 (0.09) Discontinued Operations (0.08) (0.51) 0.43 Total Non-Core $(0.08) $(0.42) $0.34 Basic EPS1 $1.34 $0.58 $0.76 Diluted EPS $1.34 $0.58 $0.76 1 See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 2 Includes lower revenue of $0.18 per share, lower O&M of $0.12 per share and lower depreciation benefit of $0.08 per share. SCE Key Core Earnings Drivers Impact of delay in 2012 GRC $0.29 Impact of SONGS2 0.02 Other revenue increases 0.01 Lower O&M (excluding SONGS) 0.02 Higher depreciation (excluding SONGS) (0.07) Higher net financing costs and other (0.05) Income taxes 0.13 Incremental repair deductions 0.07 Other income tax benefits 0.06 ____ Total $0.35

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 3 Year-to-Date Earnings Summary YTD 2013 YTD 2012 Variance Core EPS1 SCE $3.09 $2.26 $0.83 EIX Parent & Other (0.11) (0.15) 0.04 Core EPS1 $2.98 $2.11 $0.87 Non-Core Items SCE $(1.12) $— $(1.12) EIX Parent & Other Continuing Operations 0.02 0.09 (0.07) Discontinued Operations — (1.11) 1.11 Total Non-Core $(1.10) $(1.02) $(0.08) Basic EPS1 $1.88 $1.09 $0.79 Diluted EPS $1.87 $1.09 $0.78 SCE Key Core Earnings Drivers Impact of delay in 2012 GRC $0.59 Impact of SONGS2 0.05 Other revenue increases 0.10 Higher depreciation (excluding SONGS) (0.13) Higher net financing costs and other (0.09) Income taxes 0.31 Incremental repair deductions 0.16 Other income tax benefits 0.15 ____ Total $0.83 1 See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 2 Includes lower revenue of $0.20 per share, lower O&M of $0.20 per share, and lower depreciation and other items of $0.05 per share.

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 4 Note: 2013-17 forecasted capital spending subject to timely receipt of permitting, licensing, and regulatory approvals. Forecast range reflects 7% average variability in years with approved general rate case and 15% variability in years without an approved general rate case, or an average variability of 12%. Assumes sale of SCE’s Four Corners Generating Station interest in 2013. SCE Capital Expenditures Forecast ($ billions) 2013-17 Total Requested $3.8 $4.0 $4.2 $4.4 $4.2 $20.6 Range $3.7 $3.6 $3.6 $3.7 $3.6 $18.2 • CPUC GRC requests additional infrastructure replacement to approximate the mean time to failure of equipment • Includes incremental $360 million for Tehachapi Chino Hills underground single circuit configuration - does not include scope changes for FAA requirements • Includes cost estimates for West of Devers and Coolwater-Lugo transmission lines $18.2 – $20.6 billion forecasted capital program 2013 – 2017 $3.8 $4.0 2013 2014 2015 2016 2017 Distribution Transmission Generation $4.2 $4.4 $4.2

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 5 Project Name Total Project Costs1 In Service Date ROE Incentives2 2013–2017 Forecast Status3 Tehachapi $2,860 Chino Hills undergrounding in review, balance by 2016 125 bps ROE adder $917 Costs and schedule remain uncertain. Cost estimate does not include scope changes for FAA requirements. Final scope of Chino Hills undergrounding requires additional CPUC approvals. Coolwater-Lugo $813 2018 N/A $540 Filed CPCN application in Q3 2013 West of Devers $1,034 2019-2020 N/A $618 Filed CPCN application in Q4 2013 ($ millions) 1 Total Project Costs are nominal direct expenditures, subject to CPUC and FERC cost recovery approval 2 These projects have been granted CWIP in rate base and 100% abandoned plant FERC incentives 3 SCE’s estimate of $360 million nominal provided to the CPUC on April 12, 2013, is subject to change based on final scope, final engineering and other factors. SCE Large Transmission Projects

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 6 ($ billions) SCE Rate Base Forecast Note: Weighted-average year basis, including: (1) forecasted 2013-2014 FERC and 2015-2017 CPUC rate base requests; (2) consolidation of CWIP projects; and (3) estimated impact of bonus depreciation provisions through 2013. Rate Base forecast range reflects capital expenditure forecast range. • Driven by infrastructure replacement, reliability investments, and public policy requirements • FERC rate base includes CWIP and is approximately 21% of 2013 rate base forecast, increasing to 24% in 2017 • Excludes SONGS rate base, which is addressed in OII process • Includes Tehachapi Chino Hills underground single circuit configuration – excludes scope changes for FAA requirements CAGR 7 – 9% projected rate base 2013 – 2017 Requested Range $20.4 $21.8 $23.5 $25.3 $26.9 $20.5 $22.4 $24.7 $27.1 $29.3 2013 2014 2015 2016 2017

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 7 SONGS Regulatory – CPUC OII Phases Next Steps Phase 1 – Determine whether expenses and capital expenditures recorded for 2012 were reasonable; establish methodology to determine market-related costs attributable to the SONGS outages (reasonableness in Phase 3) Decision expected in Q4 2013 Phase 2 – Potential asset adjustments to rate base and interim ratemaking November 22: opening briefs December 13: reply briefs February 2014: decision Phase 3 – Reasonableness of steam generator replacement project costs; causes of the steam generator damage and allocation of responsibility Expected in 2014 Phase 4 – Potential adjustments to 2013 revenue requirement Expected in 2014 • October 2012, CPUC issued Order Instituting Investigation for SONGS outages (I.12-10-013)  Consolidates all SONGS proceedings to determine appropriate cost recovery – steam generator project, market power, capital expenditures, operations and maintenance, seismic studies  All SONGS costs since January 1, 2012, tracked in memorandum account (SONGSMA), subject to refund • October 2013, the ALJs updated the Phase 2 schedule for opening and reply briefs

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 8 SONGS Regulatory – CPUC OII Testimony • August 2013, SCE Phase 2 testimony requested return on 2013 investment1:  $425 million used and useful, materials and supplies – 7.90% through December 2017 (currently authorized cost of capital); 5.54% through 2020 (authorized weighted cost of debt and preferred)  $733 million retired – 5.54% over 5 years (authorized weighted cost of debt and preferred) • September 2013, the Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN) filed Phase 2 testimony2:  ORA requested limiting cost recovery to 75% of pre-Replacement Steam Generator plant and no return based on SONGS only operating for 3/4 of the license life (30 out of 40 years)  TURN requested a refund of return on investment after 1/30/2012, no Replacement Steam Generator recovery after 1/30/2012, and amortization of non-Replacement Steam Generator plant over the license life with no return 1 Includes construction work in progress and adjustments to deferred taxes. Please refer to August 14, 2013, SCE-40 testimony for more information. 2 Summary only. Please refer to September 10, 2013, intervener testimony for more information.

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 9 Fuel and Purchased Power Account • The Energy Resource Recovery Account (ERRA) balancing account was established in 2004 • Rates set based on annual forecast submitted in August – compliance review application for prior year submitted in April • Cost Recovery Trigger Mechanism – rate adjustment if under- or over-collection exceeds 5% of prior year generation revenue (approximately $280 million in 2013) • September 2013 ALJ proposed decision (PD) for 2013 ERRA forecast application:  Approximately $200 million rate increase  Moves $321 million forecast net SONGS market power costs to SONGSMA for consideration in OII (I.12-10-013) – PD would exclude these costs from trigger calculation  Defers $271 million of GHG cap and trade costs until implementation is finalized in R.11-03- 012 – excluded from trigger calculation • As of September 30, 2013, fuel and purchased power costs were under-collected by $719 million • Under-collection to be financed as needed by short-term debt pending resolution of SONGS OII, GHG cap and trade costs and 2014 ERRA application, which was filed in August 2013 with a proposed revenue requirement increase of $1.96 billion

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 10 2013 Core and Basic EPS Guidance Note: See Use of Non-GAAP Financial Measures in Appendix Key Assumptions: • SCE rate base model earnings of $3.39 per share • Impact of SONGS shutdown ($0.20) per share • Operating expense savings of $0.23 per share • Income tax benefits of $0.35 per share • Energy efficiency earnings of $0.03 per share, subject to Q4 CPUC action • No 2013 SONGS recoveries from Mitsubishi Heavy Industries or NEIL • No non-core items except $(1.10) per share recorded year to date • O&M cost savings flow through to ratepayers in 2015 GRC • 325.8 million common shares outstanding • EME results not consolidated • No changes in tax policy 2013 Earnings Per Share Guidance as of 8/1/13 2013 Earnings Per Share Guidance as of 10/29/13 Low Mid High Low Mid High SCE $3.50 $3.80 EIX Parent & Other (0.15) (0.15) EIX Core EPS $3.25 $3.35 $3.45 $3.60 $3.65 $3.70 Non-core Items (1.03) (1.03) (1.10) (1.10) EIX Basic EPS $2.22 $2.42 $2.50 $2.60

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 11 Drivers of Increased 2013 EPS Guidance Note: See Use of Non-GAAP Financial Measures in Appendix Co re EP S Ba sic EP S EPS Guidance Midpoint 2/26/13 SCE $3.70 • Rate base model earnings of $3.39 • Income tax repair deduction + $0.15 • O&M cost savings (net of severance) & other + $0.13 • Energy efficiency earnings + $0.03 EIX Parent & Other $(0.15) $3.55 $3.55 EPS Guidance Midpoint 6/7/13 $2.32 $3.35 EPS Guidance Midpoint 10/29/13 $2.55 $3.65 Changes 6/7/13 and 8/1/13 $(1.23) SCE • SONGS rate base $(0.15) • SONGS AFUDC on CWIP $(0.03) • SONGS other transition costs $(0.02) ($0.20) Including non-core items Changes 10/29/13 $0.23 SCE • Additional cost savings + $0.10 • Additional income tax benefits + $0.20 $0.30 Including non-core items

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 12 Creating Shareholder Value Resolve Uncertainties Create Sustainable Earnings and Dividend Growth Position for Transformative Sector Change • SCE 2012 GRC • SCE 2013 cost of capital • SCE 2012 FERC formula rate settlement • 5-year rate base CAGR of 11% (2007 – 2012) • 15% Core EPS growth (2007 – 2012) • 9 consecutive dividend increases • New business development / strategic planning • Acquired SoCore Energy (commercial solar) • Minority investments (energy efficiency, residential solar markets, electrification of transportation) • Execute wires-focused investment program • SCE 2015 GRC • SONGS cost recovery • EME bankruptcy • 7 – 9% projected rate base growth (2013 – 2017) • Optimize cost structure through operational excellence • Return to target dividend range over time • Legislative and regulatory advocacy • Rate design reform – AB 327 implementation • Evaluate new power sector business opportunities Note: See Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix W ha t W e’v e D on e W ha t R em ain s

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 13 Appendix

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 14 Updates Since Our Last Presentation • Third quarter and year-to-date results • Increased earnings guidance (p. 10-11) • New Slides  SONGS – NRC Inspection Reports (p. 22)  CAISO Load Projections (p. 27)  Solar PV Cost Trends (p. 29)  All Generation Cost Trends, Unsubsidized (p. 30)  EME Bankruptcy (p. 33)

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 15 $1.16 $1.22 $1.24 $1.26 $1.28 $1.30 $1.35 $2.07 $2.25 $2.68 $3.01 $3.33 $4.10 $3.65 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 2007 2008 2009 2010 2011 2012 2013 SCE Core EPS EIX Dividend Paid (37%) EIX Dividend Growth EIX increased its dividend for the 9th consecutive year to an annual rate of $1.35 per share for 2013 • EIX targets paying out 45 – 55% of SCE earnings • Dividend growth rate slowed to help fund large utility capital program, which is plateauing • EIX plans to return to target dividend range over time SCE Core EPS EIX Dividend 15% 2% 2007 – 2012 CAGR (38%) (42%) (46%) (54%) (56%) Note: See Use of Non-GAAP Financial Measures in Appendix for reconciliation of core earnings per share to basic earnings per share (32%) Guidance Midpoint

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 16 SONGS – Supplemental Data 1 Includes direct operations and maintenance costs, depreciation, and return on investment 2 In 2005 the CPUC authorized expenditures of approximately $525 million ($665 million based on SCE's estimate after adjustment for inflation using the Handy-Whitman Index) for SCE's 78.21% share of SONGS. Subject to CPUC reasonableness review 3 Severance costs recorded in SONGSMA until funding of post June 6, 2013, closure activities is transitioned from base rates to nuclear decommissioning trusts 4 Net of accumulated depreciation ($ millions) (SCE Share as of September 30, 2013) Since 1/1/2012 Revenue Requirement Collected1 $1,107 Steam Generator Replacement (SGRP) – Approved2 $665 SGRP Total – Incurred $602 Incremental Inspection & Repair Costs $115 Severance – Shut Down3 $56 Physical (Total) SCE Ownership 78.21% Capacity (MW) 2,150 2011 Generation (million kWh) 18,097 (As of May 31, 2013) Unit 2 Unit 3 Common Plant Total Rate Base Net Plant in Service4 $606 $430 $259 $1,295 Materials and Supplies — — 100 100 Accumulated Deferred Income Taxes (119) (74) (46) (238) Total Rate Base $487 $356 $313 $1,156 Add: Acc. Deferred Income Taxes 119 74 46 238 Add: Construction Work in Progress 25 99 106 230 Add: Nuclear Fuel 153 216 102 471 Total Net Investment $784 $745 $567 $2,096

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 17 SONGS – Asset Impairment Exposure to refunds for amounts collected from customers Exposure to recovery of net investment from future rates Regulatory Asset (as of 9/30/13)1 Net Investment at 6/6/2013 Less Impairment of $575 million2 $1,521 Nuclear Fuel 33 Other Changes 25 Regulatory Asset3 $1,579 Revenue Subject to Refund Since 1/1/12 Since 11/1/12 Authorized revenues (as of 9/30/13) $1,107 $565 Replacement power (as of 6/6/13) $680 $339 Net Investment in SONGS Net investment as of 5/31/13 $2,096 1 Such assessment and judgment is subject to considerable uncertainty, and regulatory principles and precedents are not necessarily binding and are capable of interpretation 2 Includes approximately $404 million of PP&E, including CWIP, that is expected to support ongoing activities at the site and also includes excess nuclear fuel and material and supplies that, if sold, would reduce the amount of the regulatory asset by such proceeds 3 Excludes $129 million of authorized revenues in excess of recorded revenues resulting in a Net Regulatory Asset of $1,450 million Recognition of a regulatory asset is based on an assessment that such amount is probable of recovery1 ($ millions)

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 18 SONGS – Recovery Examples Docket# Owner & Project Return of Investment Partial Return on Investment D.92-08-036 SCE – SONGS 1 generating plant   D.12-10-051 SCE – GRC Legacy Meters   D.11-05-018 PG&E – GRC Legacy Meters   D.11-09-017 Golden State Water – Hill Street Treatment Facility   D.83-08-031 Pacific Bell – Telecommunications equipment   D.92-12-057 PG&E – Geysers 15 generating plant  D.85-08-046 PG&E – Humboldt Bay 3 generating plant  D.12-10-051 SCE – GRC Mohave generating plant  D.85-12-108 SDG&E – Generating plants  Precedents are subject to interpretation and considerable uncertainty regarding their applicability to the particular circumstances of other matters, and may be found by a later commission not to be binding on that commission. No decisions have been rendered in the OII proceeding regarding recoverability of costs from future rates or refunds of amounts to customers. The CPUC may or may not agree with SCE.

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 19 SONGS Third-Party Recovery – MHI Warranty Warranty Summary Request for Arbitration • 20-year warranty:  Repair or replace defective items  Specified damages for certain repairs  $138 million liability limit, excluding consequential damages (e.g. replacement power)  Limits subject to applicable exceptions in the contract and under law • 7 invoices submitted totaling $149 million for repair costs through April 30, 2013  First invoice of $45 million ($36 million SCE share) paid, subject to audit, reservation of rights regarding documentation • October 2013, Request for Arbitration filed with the International Chamber of Commerce per MHI contract • Claims for damages consistent with July 2013 Notice of Dispute that was unsuccessfully resolved with MHI • Exceptions to damage limitations are argued to apply:  Direct Damages – $138 million warranty cap does not apply due to, among other things, gross negligence  Consequential Damages – contract waiver does not apply due to, among other things, “failure of essential purpose” SCE’s position is that the steam generator tube leak and resulting damages represent a total and fundamental failure of performance by MHI

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 20 SONGS Third-Party Recovery – NEIL Insurance • Accidental property damage and accidental outage insurance through Nuclear Electric Insurance Limited (“NEIL”)  Accidental Property Damage Policies – $2.5 million deductible; $2.75 billion liability limit  Accidental Outage Policy – weekly indemnity up to $3.5 million per unit after 12-week deductible period ($2.8 million per unit per week if both are out due to same “accident”); $490 million limit per unit ($392 million each if both units are out due to the same “accident”)  Exclusions and limitations may reduce or eliminate coverage  Proof of loss must be submitted within 12 months of damage or outage • Accidental outage policy benefits are reduced to:  80% of weekly indemnity after 52 weeks; and  10% of weekly indemnity after early retirement announcement • Separate proofs of loss have been filed for Unit 2 and Unit 3 under NEIL accidental outage policy totaling $390 million ($306 million SCE share) for amounts through June 30, 2013  SCE is continuing to make weekly indemnity claims post-shutdown decision at 10% value per the terms of the policy  SCE has not submitted a proof of loss under the accidental property damage policies – SCE has received an extension to file such a claim to December 31, 2013 • SCE expects NEIL to make a coverage determination by the end of the first quarter of 2014

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 21 SONGS – Decommissioning Decommissioning Trusts • Decommissioning Trust contributions recovered in rates approved by CPUC in triennial proceeding • December 2012, A.12-12-013 Joint Filing with SDG&E submitted • July 2013, updated early retirement scenario total decommissioning cost  SCE request that currently authorized annual decommissioning contributions of $23 million be maintained until the detailed site-specific decommissioning cost study is complete Decommissioning Process • June 2013, Certification of Permanent Cessation of Power Operations submitted to NRC • All initial decommissioning activity phase plans and cost estimates will be provided by the end of 2014 • Decommissioning involves three related activities: radiological decommissioning, non-radiological decommissioning and the management of spent nuclear fuel • Access to decommissioning funds is dependent on decommissioning process milestones and NRC staff approval for non-radiological decommissioning • Estimated decommissioning period of 2022 to 2055 may be accelerated

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 22 SONGS – NRC Inspection Reports September 2013 Inspection Report to SCE • Preliminary “white” finding (low to moderate safety significance) and an apparent violation regarding Unit 3 steam generators related to MHI computer modeling error. Preliminary “green” finding (very low safety significance) regarding Unit 2 steam generators. No financial penalties were imposed. • Both findings relate to failure as licensee to ensure that MHI’s modeling and analysis were adequate  Not unusual for the NRC to cite the licensed operator of the nuclear plant as a responsible party even when problems are created by a vendor or contractor  SCE relied upon MHI, the qualified vendor authorized to design, manufacture and test the steam generators in accordance with American Society of Mechanical Engineers Code requirements and to meet specifications  SCE appropriately questioned MHI about its design and use of computer models on multiple occasions. MHI repeatedly reassured SCE that its design and models were correct • On October, 21 2013, SCE submitted comments to the NRC on the characterizations contained in the Inspection Report but did not contest the findings or violation September 2013 Inspection Report to MHI • Notice of Nonconformance for its flawed computer modeling in the design of the steam generators • NRC’s decision to also directly cite MHI reflects the fact that MHI created the flawed design and also failed to properly perform the verification and checking that SCE hired MHI to do • NRC also noted that MHI had the same error in steam generators for four other nuclear plants and that MHI hired consultants but did not rigorously evaluate concerns they expressed about MHI’s computer modeling

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 23 Coastal Power Plants Local Reliability Areas (generalized) California Transmission System (partial, generalized) CA Once Through Cooling Policy – Legend • Short-term SONGS closure solutions  Transmission – 220 kV Barre-Ellis reconfiguration  Voltage support – Huntington Beach 3 and 4 synchronous condensers  Substations – Santiago, Viejo, Johanna capacitor bank upgrades  Generation – El Segundo repower (550 MW), Sentinel (728 MW), Walnut Creek (480 MW)  Conservation – EE, demand response, Flex Alerts • Long-term issues  Once-through cooling – approximately 6,000 MW affected in SCE territory  Air quality and emissions – limitations on permits, cap and trade market  Distributed generation and renewables – integration, flexibility and net load SCE System Reliability

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 24 SCE 2015 CPUC General Rate Case • July 2013, Notice of Intent (NOI) submitted to the CPUC’s Office of Ratepayer Advocates (ORA) • Request sets base revenue requirement for 2015 – 2017  Includes operating costs and CPUC jurisdictional capital  Excludes fuel and purchased power (and other utility cost-recovery activities), cost of capital, and FERC jurisdictional transmission • 2015 revenue requirement request of $6.279 billion  $120 million increase over presently authorized base rates  Post test year requested increase of $368 million in 2016 and additional increase of $331 million in 2017  Assumes full recovery of SONGS rate base and net investment – O&M, capex tied to early retirement • Request consistent with SCE strategy to ramp up infrastructure investment consistent with capital plan while mitigating customer rate impacts through productivity and lower operating costs • September 2013, ORA accepted SCE’s NOI - GRC application scheduled to be filed in Q4 2013  no material changes expected from NOI July 15 Notice of Intent GRC Application Evidentiary Hearings Opening and Reply Briefs Final Decision Proposed Decision 2013 2014 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Estimated

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 25 3 4 5 6 7 10/1/12 10/1/13 10/1/14 10/1/15 Ra te (% ) CPUC Cost of Capital • Interest rates did not trigger change to SCE’s Return on Equity (ROE) for 2014 and will continue at 10.45%  As of September 2013, index average was 4.80% • 10.45% ROE and adjustment mechanism approved through 2015  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 basis point 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%  SCE will submit new application in April 2015 for Cost of Capital in 2016 CPUC Adjustment Mechanism Moody’s Baa Utility Index Spot Rate Moving Average (10/1/12 – 9/30/13) = 4.80% 100 basis point +/- Deadband Starting Value – 5.00%

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 26 2012 FERC Formula Rate Settlement • August 2011, FERC accepted SCE’s formula rates subject to refund and settlement • August 2013, SCE filed settlement for rates retroactive to January 1, 2012 • 10.45% settlement ROE:  9.30% base  + 50 bps CAISO participation  + 65 bps weighted average for project incentives • Moratorium on ROE changes through June 30, 2015, when formula rate changes once again can be requested • If settlement is approved by November 15, 2013, next formula rate update submitted on December 1, 2013, is effective on January 1, 2014 • Settlement will result in customer refunds of approximately $200 million during 2014 and 2015 • No material impact on SCE earnings in 2013

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 27 CAISO Load Projections Renewables • Current 33% RPS by 2020 set as floor for CPUC per AB327 • More variable and less predictable output • Output does not fully match demand • Need for flexible, dispatchable capacity Resource Adequacy • 1-year forward • 10-year forward long-term procurement process for new resources • Need intermediate (3 – 5 years) forward capacity market with right mix of operational attributes Increasing renewable generation creates need for substantial amount of flexible, dispatchable capacity Source: CA Independent System Operator, “2013 Special Reliability Assessment”, September 18, 2013 and represents a single day in March of each year. CAISO ‘Peaking’ Duck Chart 10,000 12,000 14,000 16,000 18,000 20,000 22,000 24,000 26,000 28,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 MW CAISO Net Load --- 2012 through 2020 2012 (Actual) 2013 (Actual) 2014 2015 2016 2017 2018 2019 2020 Hour Ending Net Load = Load - Wind - Solar

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 28 Distributed Generation • Distributed generation (DG) will be a key part of the future generation mix due to:  Rapidly declining cost of solar photovoltaic panels  Challenges to building new generation and transmission facilities  Public policy support Rate Design Investment EIX is focused on properly integrating DG into the grid through rate design and NEM reform, and making investments in emerging technologies • AB 327 • CPUC Order Instituting Ratemaking • Monthly fixed charge • Net energy metering (NEM) tariff structure • Small, targeted investments  SoCore Energy (acquisition) – commercial / industrial DG developer  Optimum Energy (investment) – energy optimization  Clean Power Finance (investment) – solar industry financial services and software provider

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 29 Solar PV Cost Trends $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 $11.00 $12.00 1998 2000 2002 2004 2006 2008 2010 2012 Me dia n V alu e p er W at t ( 20 12 $ ) ≤ 10 kW 10-100 kW > 100 kW Over the past decade, real installed solar system prices have fallen by nearly 50% Note: Dollar values are in real 2012 dollars before state/local incentives. Median installed prices are shown only if 15 or more observations are available for the individual size range. Source: Lawrence Berkeley National Laboratory, “Tracking the Sun VI: An Historical Summary of the Installed Price of Photovoltaics in the United States from 1998 to 2012,” Figure 7

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 30 All Generation Cost Trends, Unsubsidized $0.149 $0.109 $0.065 0.061 $0.086 $0.089 $0.045 $0.123 $0.067 $0.108 $0.144 $0.086 $0.000 $0.050 $0.100 $0.150 $0.200 $0.250 Solar PV (Distributed) Fuel Cell Coal Gas (CCGT) Nuclear Solar PV (Utility Scale) Wind (Utility Scale) Lazard 2012 Levelized Cost of Energy (range) EIA 2012 Levelized Cost of Energy $0.087 $0.122 $0.095 $0.204 $0.206 $0.145 $0.104$/ kW h Distributed Generation Central Station / Utility Scale Generation Sources: Lazard Levelized Cost of Energy Version 7.0 August 2013; EIA Levelized Cost of Energy Analysis 2013 The levelized cost of energy for distributed generation resources continues to move toward equilibrium with other generation sources

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 31 Legislative Rate Reform – AB 327 September 2013, Assembly Bill 327 (Perea) provides the following changes to rate structure (subject to further CPUC rulemaking) • Rate Reform  Removes tier restrictions on residential rates  Allows fixed charge up to $10/month ($5 for low income) in 2015 and CPI indexing in 2016  Establishes 30 – 35% discounts for low income customers  Delays residential time-of-use pricing from 2013 to 2018 • Renewables and Net Energy Metering (NEM)  Allows CPUC to require IOUs to procure more than 33% RPS within existing program rules  Codifies full retail NEM cap for current program – 2,240 MW for SCE  Requires NEM tariff program in 2017 without a program cap but that considers impacts to all customers and the grid  Requires grandfathering period for existing NEM customers using a ‘reasonable payback period’ based on year customers took service 12.8¢ 16.0¢ 27.1¢ 31.1¢ 0 5 10 15 20 25 30 35 0 200 400 600 800 1,000 1,200 1,400 ¢/ kW h kWh/month Tier 1 Tier 2 Tier 3 Tier 4 2013 SCE Residential Rate Structure1,2,3 1 Tier structure revised based on the 2012 GRC Phase II proposal approved on March 21, 2013 2 Based on a daily baseline of 342 kWh/month, which is a customer weighted average of baseline allocations of each region SCE serves. Tier 4 does not have a kWh limit. 3 Tier 1 and 2 rates are subject to rate caps established in 2001, as modified by SB695 in 2009

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 32 SCE Distribution Program • Average equipment age beginning to approach mean time to failure making it critical to achieve equilibrium replacement rates • 2015 GRC request represents ~120% increase in infrastructure replacement over 2012 GRC Authorized • Demonstrated operational capability to execute current infrastructure replacement programs • Slow growth in California economy, resulting in less customer growth, allows for increased infrastructure replacement expenditures 2015 – 2017 Requested GRC Expenditures in Distribution Assets $9.3 Billion 1 Includes information technology, facilities/buildings, corporate center, etc. 2 Includes underground conversions, customer requests/relocations, claims, customer meters, etc. Load Growth New Service Connections Infrastructure Replacement General Plant1 Other2 Achieving equilibrium replacement rates requires a sustained commitment over multiple rate case cycles creating a long-term growth opportunity

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 33 SCE Energy Efficiency Programs 1.7 1.6 0.9 0.9 2011 2012 2013 2014 Energy efficiency programs updated for 2013 – 2014 • SCE is a national leader  2012 energy savings = 1.8% of retail sales1 • 2013 budget of $347 million2 • Target 0.9 billion kWh average annual savings for 2013-14 cycle3 – Reduced goals reflect CPUC-identified market potential for energy efficiency Energy efficiency earnings incentive mechanism modified • December 2012 – $15 million awarded for 2010 program year • New earnings mechanism for 2011, 2012 (payable in 2013, 2014) based on 5% management fee and up to 1% performance bonus • SCE to file earnings claim for 2011 program activity this year – actual payment, if any, subject to CPUC approval • CPUC approved new incentive mechanism for 2013 and 2014 activities (payable in 2014 and beyond) comprised of performance rewards and management fees 1 Does not include resale sales. Energy savings subject to ex-post CPUC review. 2 Excludes income qualified energy efficiency and integrated demand-side management program funding authorizations for 2013. 3 Based on CPUC goals established for SCE. Market potential changes in response to program funding levels, customer participation assumptions, market influences and the implementation of new building codes and minimum appliance efficiency standards Annual kWh Savings (billions)

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 34 EME Bankruptcy • December 2012, EME and certain of its wholly-owned subsidiaries filed voluntary petitions for Chapter 11 bankruptcy • EIX recorded full impairment of EME in 2012 and no longer consolidates EME earnings and losses • July 2013, Transaction Support Agreement terminated by Consenting Noteholders  Extension of the Tax Allocation Agreement in the TSA no longer effective and the current expiration date reinstated – December 31, 2013  Claims EIX submitted on a contingent basis reinstated and EIX subject to claims of EME or creditors • August 2013, unsecured creditor committee filed Motion for Standing and claims in bankruptcy court and was accompanied by a proposed complaint against EIX • October 2013, EME announces Plan Sponsor Agreement which includes an NRG proposal to acquire EME and a term sheet for a Plan of Reorganization  Proposal would supersede August 2013 Motion for Standing  EME would retain the right on behalf of creditors to pursue any claims against EIX  EIX has pending claims in the bankruptcy as well  EIX reserves its rights regarding the Plan of Reorganization, which is subject to bankruptcy adjudication process EIX does not know if the August 2013 complaint or other complaints will be filed, but it would vigorously contest the allegations included in the complaint

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 35 Earnings Per Share Attributable to SCE Core EPS Non-Core Items Tax settlement Health care legislation Regulatory and tax items Total Non-Core Items Basic EPS SCE Core EPS Non-GAAP Reconciliations Note: See Use of Non-GAAP Financial Measures Reconciliation of SCE Core Earnings Per Share to SCE Basic Earnings Per Share 2007 $2.07 — — 0.10 0.10 $2.17 2008 $2.25 — — (0.15) (0.15) $2.10 2009 $2.68 0.94 — 0.14 1.08 $3.76 2010 $3.01 0.30 (0.12) — 0.18 $3.19 CAGR 15% 17% 2011 $3.33 — — — — $3.33 2012 $4.10 — — 0.71 0.71 $4.81

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 36 Non-GAAP Reconciliations ($ millions) Note: See Use of Non-GAAP Financial Measures. EME’s financial results are reported as non-core for all periods Q32012 $363 (37) $326 $– 31 (167) (136) $190 Q32013 $477 (14) $463 $– – (25) (25) $438 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 Continuing Operations Discontinued operations Total Non-Core Basic Earnings YTD2012 $736 (50) $686 $– 31 (360) (329) $357 YTD2013 $1,007 (34) $973 $(365) 7 (1) (359) $614

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM October 29, 2013 37 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. Use of Non-GAAP Financial Measures EIX Investor Relations Contacts Scott Cunningham, Vice President (626) 302-2540 scott.cunningham@edisonintl.com Felicia Williams, Senior Manager (626) 302-5493 felicia.williams@edisonintl.com