Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 0 Third Quarter 2012 Financial Teleconference

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 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 liquidity and restructuring activities, 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 2011 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. Forward-Looking Statements

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 2 Third Quarter Earnings Summary 1 See Earnings Non-GAAP Reconciliations And Use of Non-GAAP Financial Measures in Appendix. The impact of participating securities is included in EIX parent company and other, and was zero per share for the quarters ended September 30, 2012, and September 30, 2011. 2 EIX parent company and other for the quarter ended September 30, 2012, includes $(0.09) per share for state income tax adjustments related to prior and future periods. 3 Non-core items for the quarter ended September 30, 2012, include Homer City, Edison Capital asset sale, and other. Non-core items for the quarter ended September 30, 2011, include earnings for Homer City only. Q3 11 Q3 12 Variance Core EPS1 SCE $1.25 $1.11 $(0.14) EMG 0.05 (0.28) (0.33) EIX parent company and other2 (0.04) (0.11) (0.07) Core EPS $1.26 $0.72 $(0.54) Non-Core Items SCE $ — $ — $ — EMG3 0.05 (0.14) (0.19) EIX parent company and other — — — Total Non-Core $ 0.05 $(0.14) $(0.19) Basic EPS $1.31 $0.58 $(0.73) Diluted EPS $1.30 $0.58 $(0.72) Basic EPS Q3 11 Q3 12 $1.31 $0.58 $426 $190 GAAP Earnings ($ millions) Q3 11 Q3 12 Core EPS Q3 11 Q3 12 $1.26 $0.72 Core Earnings ($ millions) $411 $235 Q3 11 Q3 12

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 3 $(0.05) (0.04) (0.09) (0.06) 0.06 0.04 $(0.14) SCE Third Quarter Highlights 2012 GRC delay items: Depreciation Net interest expense SONGS Inspection and repair Severance O&M reductions and other Income taxes and other Total Recent Developments • September 2012, SCE filed proposed formula rate update with 2013 transmission revenue requirement of $900 million, representing an increase of $178 million, or 25%, over 2012 revenue requirement • October 2012:  2012 GRC Proposed Decision released (see page 4)  CPUC approved SONGS OII to consider appropriate cost recovery – all SONGS costs since January 1 tracked in separate memo account (see page 7)  SCE submitted response to Confirmatory Action Letter and restart plans for Unit 2 to the NRC (see page 7) EPS Core1 Non-Core Items Basic EPS1 Q3 12 $1.11 — $1.11 Variance $(0.14) — $(0.14) Q3 11 $1.25 — $1.25 Key Core Earnings Drivers 1 See Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix for reconciliation of core earnings per share to basic earnings per share.

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 4 SCE 2012 CPUC General Rate Case (A.10-11-015) • Proposed Decision issued on October 19 with 2012 revenue requirement of $5,693 million  Decrease of $601 million from SCE’s request primarily related to O&M with some plant-related capital reductions  $929 million capital expenditures removed (2010 – 2012)  Proposed CPUC rate base of $15,086 million in 2012  Proposed post-test year escalation on capital additions of 3.05% for 2013, and 2.93% for 2014  SONGS revenue requirement subject to refund and reasonableness review, and tracked in memorandum account pending outcome of outage investigation • SCE believes PD is consistent with Range Cases provided in rate base forecast • Final decision retroactive to January 1, 2012, through memorandum account, except for SONGS  SCE expects to adjust its total spending to amount authorized by Commission  SCE’s ongoing goal is to earn its authorized returns as set by the CPUC and FERC

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 5 1 Forecasted 2012-2014 FERC and CPUC capital spending while final GRC decision is pending, subject to timely receipt of permitting, licensing, and regulatory approvals. Forecast range reflects an 11% variability to annual expenditure levels related to execution risk, scope change, delays, regulatory constraints, and other contingencies. Variability based on average level of actual variability experienced from 2009 through 2011. 2 Capital expenditure forecast updated for GRC Proposed Decision only. SCE Capital Expenditures Forecast Total Forecast Range1 $5.0 $4.4 $3.8 $13.2 $4.4 $4.0 $3.4 $11.8 $3.9 $5.0 $4.4 $3.8 2011 2012 2013 2014 By Proceeding % 2012 CPUC Rate Case 68 FERC Cases 29 Total 100 Other CPUC 3 Forecast By Classification $ % Solar Photovoltaic 0.2 1 Edison SmartConnect® 0.4 3 Generation 1.7 13 Transmission 3.8 29 Distribution 7.1 54 Total 13.2 100 ($ billions) Due to GRC delay, 2012 capital expenditures expected to be below forecast range GRC PD2 $4.6 $4.2 $3.7 $12.5 Request Range

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 6 Rate Base 7-9% 2012 – 2014 CAGR2 • Rate base forecast1 based on 2012 CPUC GRC request and 2012 FERC Formula Rate • FERC rate base includes CWIP and increases to approximately 20% of 2014 forecast • Forecast subject to change based on timely receipt of permitting, licensing, capital deployment, and regulatory approvals on capital expenditures • GRC PD, if adopted, would result in forecasted rate base of $20.1 billion in 2012, $21.7 billion in 2013, and $23.4 billion in 2014 ($ billions) SCE Rate Base Forecast $19.9 $21.2 $22.8 $20.8 $22.6 $24.7 2012 2013 2014 1 Forecast range is weighted-average year basis and includes: (1) forecasted 2012-2014 CPUC and FERC rate base requests; (2) SCE Solar PV program including CPUC approved petition for modification; (3) consolidation of CWIP projects; (4) estimated impact of bonus depreciation provisions. Rate Base forecast reflects SCE Capital Expenditures Forecast range. 2 Forecasted Rate Base and related earnings per share may vary depending on authorized revenues and cost of capital, including financing costs, operating expenses, taxes, and other revenue activities. 3 Based on capital expenditure forecast updated for GRC Proposed Decision only. GRC PD3 $20.1 GRC PD3 $21.7 GRC PD3 $23.4

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 7 SONGS Update • SCE submitted CAL response and restart plans for Unit 2 to NRC  Operate at 70% power for 5 months with follow up outage and inspection  No assurance about NRC review time or approval of restart request  Repairs to restart Unit 2 at reduced power levels substantially completed • Unit 3 will not restart this year • August 2012, SCE announced plans for downsizing to bring SONGS in line with industry peers  $30 million estimated cash severance costs recorded in the third quarter • September 2012, SCE submitted $45 million invoice to MHI for some costs through June 30, 2012, for all owners’ repair costs • October 2012, SONGS filed separate proofs of loss for Unit 2 and Unit 3 under NEIL outage policy • October 2012, CPUC issued Order Instituting Investigation (OII) to consolidate all SONGS issues in related regulatory proceedings and consider appropriate cost recovery  All SONGS-related costs after January 1 tracked in separate memorandum account  SCE will file its response by November 24 and must also file testimony by December 10 detailing costs subject to refund Operational Financial Regulatory

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 8 $(0.21) 0.02 (0.01) (0.05) (0.08) $(0.33) EMG Third Quarter Highlights Recent Developments • September 2012, Homer City entered into Master Transaction Agreement and in October 2012 Plan Support Agreement – discontinued operations accounting treatment beginning third quarter 2012 • Waukegan 7 request to extend unit-specific retrofit requirements from December 31, 2013, to December 31, 2014, granted by IL Pollution Control Board 1 See Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix for reconciliation of core earnings per share to basic earnings per share. 2 Homer City’s financial results are reported as non-core for both quarters, resulting in a $(0.24) per share loss for the quarter ended September 30, 2012, and earnings of $0.05 per share for the quarter ended September 30, 2011. Non-core items for the quarter ended September 30, 2012, also include a $0.09 per share gain from Edison Capital’s sale of its Beaver Valley lease interest, and other. 3 Includes per share impact of unrealized losses of $(0.01) in both periods. EPS Core1 Non-Core Items2 Basic EPS1 Q3 12 $(0.28) (0.14) $(0.42) Variance $(0.33) (0.19) $(0.52) Q3 11 $0.05 0.05 $0.10 Key Core Earnings Drivers Midwest Generation3 EMMT - trading Renewable energy projects Natural gas projects Higher income taxes and other Total

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 9 Credit Facility1 Credit Facility (availability) Cash & Cash Equivalents Available Liquidity Liquidity Profile 1 Credit facilities expire May 2017. 2 EME had corporate cash of $627 million at September 30, 2012. Corporate cash is defined as cash and cash equivalents of EME and its subsidiaries that do not have contractual third-party dividend restrictions. Sources $— $— 698 $698 EME & Subs2 $2,750 $2,174 96 $2,270 SCE $1,250 $1,222 138 $1,360 EIX parent co. & other September 30, 2012 ($ millions) • Recognized EME tax benefits of $1.0 billion available under EIX tax-allocation agreement  EME recognized tax-allocation benefits related to net operating loss carryforwards of $790 million and production tax and other credit carryforwards of $236 million  EMG made approximately $185 million tax-allocation payment to EIX. EME expects to receive $160 million tax-allocation payments from EIX during next six months $— $— 154 $154 Other EMG Subs

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 10 EME Financial Status • October 2012, EME and EIX entered into non-disclosure agreements with certain EME unsecured bondholders • Based on current projections, EME is not expected to have sufficient liquidity to repay $500 million debt obligation due June 2013 • No assurance $97 million interest payments due on 2017, 2019, and 2027 EME unsecured bonds will be paid on November 15  Failure to pay will likely result in EME's filing for protection under Chapter 11 of the U.S. Bankruptcy Code  Chapter 11 filing will trigger cross defaults under other outstanding EME obligations • October 2012, EME and MWG entered into a non-disclosure agreement with an advisor representing a majority in principal amount of MWG’s senior lease obligation bonds

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 11 Appendix

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 12 Updates Since Our Last Presentation • Q3 2012 results and standard information • SCE 2012 CPUC General Rate Case (p. 4) • SCE Capital Expenditures Forecast (p. 5) • SCE Rate Base Forecast (p. 6) • SONGS Update (p. 7) – New Slide • EME Financial Status (p. 10) • SCE 2013 Cost of Capital Application (p. 21) • SONGS – Net Investment and Rate Base (p. 22) – New Slide • SONGS – Supplemental Data (p. 23)

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 13 Dividend Growth SCE earnings and rate base growth have expanded faster than EIX’s dividend as a result of utility’s capital program $1.08 $1.16 $1.22 $1.24 $1.26 $1.28 $1.89 $2.07 $2.25 $2.68 $3.01 $3.33 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 2006 2007 2008 2009 2010 2011 SCE Core EPS EIX Dividend Paid • EIX targets paying out 45 – 55% of SCE earnings • Dividend not growing at same rate as SCE core earnings and is below target payout ratio due to large utility capital program • EIX plans to return to target dividend range over time as SCE capital spending program declines from its peak, but there can be no assurance SCE Core EPS1 EIX Dividend 12% 4% 2006 – 2011 CAGR (38%) (42%) (46%) (54%) (56%) (57%) 1 See Use of Non-GAAP Financial Measures in Appendix for reconciliation of core earnings per share to basic earnings per share. 1

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 14 Year-to-Date Earnings Summary 1 See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. The impact of participating securities is included in EIX parent company and other and was zero for the year-to-date periods ended September 30, 2012, and September 30, 2011. 2 EIX parent company and other for year-to-date period ended September 30, 2012 includes $(0.09) per share for state income tax adjustments related to prior and future periods. 3 Non-core items for the year-to-date period ended September 30, 2012, include Homer City, Edison Capital asset sale, and other. Non-core items for the year-to-date period ended September 30, 2011, include earnings for Homer City and other. YTD 11 YTD 12 Variance Core EPS1 SCE $2.57 $2.26 $(0.31) EMG (0.04) (0.71) (0.67) EIX parent company and other2 (0.06) (0.15) (0.09) Core EPS $2.47 $1.40 $(1.07) Non-Core Items SCE $ — $ — $ — EMG3 (0.01) (0.31) (0.30) EIX parent company and other — — — Total Non-Core $(0.01) $(0.31) $(0.30) Basic EPS $2.46 $1.09 $(1.37) Diluted EPS $2.45 $1.09 $(1.36) YTD 11 YTD 12 $802 $357 YTD 11 YTD 12 $2.46 $1.09 YTD 11 YTD 12 $805 $455 $1.40 $2.47 YTD 11 YTD 12 Core Earnings ($ millions) Core EPS GAAP Earnings ($ millions) Basic EPS

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 15 $(0.14) (0.11) (0.17) (0.06) 0.15 0.02 $(0.31) 2012 GRC delay items Depreciation Net interest expense SONGS Inspection and repair Severance O&M reductions and other Income taxes and other Total SCE Year-to-Date Highlights 1 See Use of Non-GAAP Financial Measures in Appendix for reconciliation of core earnings per share to basic earnings per share. Key Core Earnings Drivers EPS Core1 Non-Core Items Basic EPS1 YTD 11 $2.57 — $2.57 YTD 12 $2.26 — $2.26 Variance $(0.31) — $(0.31)

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 16 EMG Year-to-Date Highlights 1 See Use of Non-GAAP Financial Measures in Appendix for reconciliation of core earnings per share to basic earnings per share. 2 Homer City’s financial results are reported as non-core for both periods, resulting in a $(0.40) per share loss for the year-to-date period ended September 30, 2012, and zero per share for the year-to-date period ended September 30, 2011. Non-core items for the year-to-date period ended September 30, 2012, also include $0.09 per share gain from Edison Capital’s sale of its Beaver Valley lease interest, and other. 3 Includes impact of unrealized losses of $(0.01) per share for the year-to-date period ended September 30, 2012, and losses of $(0.01) per share for the year-to-date period ended September 30, 2011. Key Core Earnings Drivers EPS Core1 Non-Core Items2 Basic EPS1 YTD 11 $(0.04) (0.01) $(0.05) YTD 12 $(0.71) (0.31) $(1.02) Variance $(0.67) (0.30) $(0.97) Midwest Generation3 Renewable energy projects Natural gas projects Higher net interest expense Higher income taxes and other Total $(0.48) (0.01) (0.07) (0.02) (0.09) $(0.67)

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 17 Calendar Year Short- and Long-Term Debt Maturities SCE EME1,2 EIX Debt Maturity Profiles 2013 2012 2014 2015 $380 27 28 September 30, 2012 ($ millions) $— 591 — $1,200 294 — $300 72 — 1 Includes project finance and other non-recourse debt. 2 Assumes conversion of $340 million outstanding Walnut Creek construction loan to term loan in 2013.

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 18 Earnings Attributable to Edison International Core Earnings1 SCE EMG EIX parent company and other EIX Core Earnings Non-core items EMG – Sale of Beaver Valley lease interest Earnings (loss) from discontinued operations2,3 EMG – Homer City EMG – Homer City impairment and other charges EMG – Other Total Non-core items EIX GAAP Earnings Non-GAAP Reconciliations ($ millions) 1 See Use of Non-GAAP Financial Measures. 2 Homer City’s financial results are reported as non-core for both quarters, resulting in a $(79) million loss for the quarter ended September 30, 2012, and earnings of $15 million for the quarter ended September 30, 2011. 3 Homer City’s financial results are reported as non-core for both periods, resulting in a $(131) million loss for the year-to-date period ended September 30, 2012, and zero per share for the year-to-date period ended September 30, 2011. Q3 11 $406 18 (13) $411 $ — 15 — — 15 $426 Q3 12 $363 (92) (36) $235 $31 (11) (68) 3 (45) $190 Reconciliation of EIX Core Earnings to EIX GAAP Earnings YTD 11 $838 (14) (19) $805 $ — — — (3) (3) $802 YTD 12 $736 (233) (48) $455 $31 (50) (81) 2 (98) $357

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 19 SCE Appendix

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 20 $11.4 $12.5 $13.1 $15.0 $16.8 $18.8 2006 2007 2008 2009 2010 2011 Rate Base1 Core Earnings2 11% 12% 2006 – 2011 CAGR 1 Recorded rate base, year-end basis. 2 See Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. Core Earnings2 $1.89 $2.07 $2.25 $2.68 $3.01 $3.33 SCE Historical Rate Base and Core Earnings ($ billions)

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 21 • On April 20, 2012, SCE filed its application to set the capital structure and cost of capital (A.12-04-015) • Requested Return on Common Equity (ROE) of 11.1%:  Capital needs are relatively high compared to other electrics  Financial strength needed to attract capital for aggressive State policy goals  Relatively lower ROE in other jurisdictions does not reflect SCE business and financial risks Proposed Phase II Schedule SCE 2013 Cost of Capital Application Cost of Capital Capital Structure Adjustment Mechanism P h a se I P h a se I I Current Proposed 2013 Revenue Impact • Long Term Debt – 43% • Preferred Debt – 9% • Equity – 48% • Long Term Debt – 43% • Preferred Debt – 9% • Equity – 48% • None • Long Term Debt – 6.22% • Preferred Debt – 6.01% • Equity – 11.5% • Long Term Debt – 5.49% • Preferred Debt – 5.79% • Equity – 11.1% • $132 million reduction based on 2012 GRC request, or 0.2 cents/kWh Annual ROE trigger mechanism: • Moody’s Baa bond index 12-month average • ½ difference adjustment when 1 percentage point deadband is exceeded • Continue annual trigger mechanism for 2014 and 2015 • None Utilities Supplemental Testimony Intervenor Testimony Rebuttal Testimony Hearings Proposed Decision Final Decision Oct. 26 Nov. 30 Dec. 14 Jan. 14 – 15, 2013 March, 2013 April, 2013 Utilities Supplemental Testimony Intervenor Testimony Rebuttal Testimony Hearings Proposed Decision Final Decision June 28 August 6 August 29 September 14 – 28 November 29 December 20 Proposed Phase I Schedule

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 22 SONGS – Net Investment and Rate Base 1 Net of accumulated depreciation. Includes Construction Work in Progress, nuclear fuel, and materials and supplies. Unit 2 Unit 3 Common Plant Total Net Investment Net plant in service1 $593 $418 $261 $1,272 Materials and supplies — — 99 99 Construction work in progress 77 141 76 294 Nuclear fuel 153 212 101 466 Total Net Investment1 $823 $771 $537 $2,131 Rate base Net plant in service1 $593 $418 $261 $1,272 Materials and supplies — — 99 99 Accumulated deferred income taxes (95) (45) (66) (206) Amounts in Rate Base $498 $373 $294 $1,165 September 30, 2012 ($ millions)

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 23 SONGS – Supplemental Data 1 Energy and capacity net of avoided nuclear fuel costs. Represents about 7% of SCE’s total fuel and purchased power expense incurred year to date September 30, 2012. 2 Adjusted for inflation from $525 million (2004$) authorized by CPUC in 2005. 3 Includes $95 million CWIP primarily related to disposal of old steam generators. 4 Includes $170 million nuclear fuel-related and decommissioning costs, and $650 million direct operations and maintenance costs, depreciation and return on investment. 2012 Outage Impacts (SCE share) Inspection & Repair Costs – Incurred $96 Net Market Costs – Incurred1 $221 Regulatory (SCE share) Steam Generator Replacement (SGR) Project – Approved2 $665 SGR Project – Incurred3 $594 Estimated 2012 Annual Revenue Requirement4 $820 Physical (Total) SCE Ownership 78.21% Capacity (MW) 2,150 2011 Generation (million kWh) 18,097 September 30, 2012 ($ millions)

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 24 SONGS – Warranty and Insurance MHI Warranty • 20-year warranty with Mitsubishi Heavy Industries  Repair or replace defective items  Specified damages for certain repairs  $138 million liability limit and excludes consequential damages (e.g., replacement power)  Limits subject to applicable exceptions  September 2012, SCE submitted $45 million invoice to MHI for some costs through June 30, 2012 for all owners’ repair costs NEIL Insurance • Property damage and outage insurance through Nuclear Electric Insurance Limited (―NEIL‖)  ―Accidental Property Damage‖ – $2.5 million deductible; $2.75 billion liability limit  Outage from ―Accidental Property Damage‖ – up to $3.5 million per week for each 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  October 2012, SONGS filed separate proofs of loss for Unit 2 and Unit 3 under NEIL outage policy There is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 25 Project Name Project Lifecycle Phase In Service Date Direct Project Costs1 % of Spend Complete 2012-2014 Forecast1 Tehachapi 1-112,3 Construction 2015 $2,500 69% $904 Devers-Colorado River3 Construction 2013 860 33% 709 Eldorado-Ivanpah4 Engineering / Construction 2013 444 11% 417 Red Bluff Construction 2013 234 28% 220 Alberhill Licensing 2015 315 8% 242 San Joaquin Cross Valley Loop Engineering / Construction 2014 190 14% 170 SCE Transmission Program Transmission expenditures are needed to improve system reliability and increase access to renewable energy Eldorado Ivanpah San Joaquin Cross Valley Loop Los Angeles Vincent San Diego Pardee Antelope Palmdale Santa Ana SCE Service Territory Santa Clarita Valley Mira Loma Devers Palm Springs Windhub San Joaquin Cross Valley Loop Colorado River Rector Whirlwind Ivanpah Eldorado Highwind Alberhill Tehachapi Segments 1-3 500kV Tehachapi Segments 4-11 500kV DCR 500kV Alberhill Redbluff Redbluff Existing Substation 1 FERC and CPUC jurisdictional assets. Direct expenditures include direct labor, land and contract (materials & contractor) costs incurred for each project and excludes allocated overhead costs included in the SCE Capital Expenditures Forecast for 2012 - 2014. Subject to timely receipt of permitting, licensing, and regulatory approvals. 2 Tehachapi segments 1-3A were energized and in-service in 2009. The remainder is under construction and will be phased into service through 2015. 3 SCE has experienced significant cost pressures on its Tehachapi and Devers-Colorado River Transmission Projects, primarily related to environmental monitoring and mitigation costs, scope changes, and schedule delays. Related CPUC filings will be updated when final engineering is completed. 4 Eldorado-Ivanpah Project received CPUC approval at $411 million related to reduced contingency. SCE has the ability to file an updated cost when final engineering is completed. September 30, 2012

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 26 ER11-3697 06/03/11 Settlement discussions on 2012 formula rate filing in progress Next settlement conference to be held on December 5th and 6th, 2012 12/05/11 FERC rejected SCE’s request for rehearing on ROE, and SCE has initiated court appeal SCE filed reply brief on ROE at DC Circuit on August 20 and scheduling of oral argument pending 09/14/12 2013 formula rate update filed; parties filed protests and motions to consolidate on 10/5/12 FERC hearing/settlement order expected by mid-November A. 07-06-031 06/28/07 CPUC restrictions during evaluation of Petition for Modification and Assigned Commissioner's Ruling regarding Chino Hills continue to impact construction on Segments 7 and 8 CPUC approval for Petition for Modification for aviation marking and lighting expected Q2 2013; Response to Scoping Memo and Assigned Commissioner Ruling due February 2013 A. 05-04-015 04/11/05 Construction began January 2012 Revised costs to be filed with CPUC in Q4 2012 A. 09-05-027 05/28/09 Nevada PUC PTC approval obtained March 2012. Construction commenced March 2012 Forecast in-service July 2013 A. 09-09-022 09/30/09 Permit to Construct filed September 2009 converted to a CPCN filing March 2010. Amended Proponent’s Environmental Assessment (PEA) per CPUC request submitted April 2011 Draft Environmental Impact Report (EIR) expected from the CPUC Q4 2012 Other SCE Key Regulatory Events Devers-Colorado River Transmission Tehachapi Transmission Eldorado-Ivanpah Transmission Alberhill Case Number Date of Filing Status Next Milestone FERC Formula Rate Filing

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 27 $1,754 — 623 399 73 1,095 659 (95) 564 176 388 25 $363 $1,977 1,694 283 — — 1,977 — — — — — — $— $3,731 1,694 906 399 73 3,072 659 (95) 564 176 388 25 $363 $363 — $363 $1,759 — 566 358 71 995 764 (98) 666 245 421 15 $406 $1,627 1,374 253 — — 1,627 — — — — — — $— $3,386 1,374 819 358 71 2,622 764 (98) 666 245 421 15 $406 $406 — $406 SCE Results of Operations ($ millions) 1 See Use of Non-GAAP Financial Measures. Utility Earning Activities Utility Cost- Recovery Activities Total Consolidated Three Months Ended Sept 30, 2011 Utility Earning Activities Utility Cost- Recovery Activities Total Consolidated Three Months Ended Sept 30, 2012 Operating Revenue Fuel and purchased power Operation and maintenance Depreciation, decommissioning and amortization Property and other taxes Total operating expenses Operating income Net interest expense and other Income before income taxes Income tax expense Net income Dividends on preferred and preference stock not subject to mandatory redemption Net income available for common stock Core Earnings1 Non-Core Earnings1: Tax settlement Total SCE GAAP Earnings

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 28 Earnings Per Share Attributable to SCE Core EPS1 Non-core items Tax settlement Health care legislation Regulatory and tax items Generator settlement/refund incentive Total non-core items Basic EPS SCE Core EPS Non-GAAP Reconciliations 1 See Use of Non-GAAP Financial Measures. Reconciliation of SCE Core Earnings Per Share to SCE GAAP Earnings Per Share 2006 $1.89 — — 0.40 0.09 0.49 $2.38 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 12% 7% 2011 $3.33 — — — — — $3.33

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 29 EME Appendix

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 30 Owned and Operated1 Coal2 Natural Gas Wind3 Other Total MW 4,354 1,269 1,660 153 7,436 % 59 17 22 2 100 Under Construction Wind Natural Gas4 Wind Development Pipeline5 MW 120 479 MW ~700 67 44 19 244 190 357 4,314 167 133 305 40 144 EME Business Platform September 30, 2012 1 Natural gas includes oil-fired; other includes Doga in Turkey (144 MW) and Huntington biomass (9 MW), which are not shown. 2 Excludes Fisk (326 MW) and Crawford (532 MW) stations shut down in September 2012. 3 Includes operating projects reflected on a net basis based on EME’s interest to reflect Capistrano Wind Partners (CWP) closing in the quarter ended March 31, 2012. 4 Deliveries under the power sales agreement are expected to commence in 2013. 5 Owned or under exclusive agreement. 240 964 479 120 55

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 31 1 Includes the price of energy, capacity, ancillary services, etc. 2 Average realized gross margin is equal to all-in average realized price less average fuel and emission costs. 3 See Other Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. 4 Excludes Fisk (326 MW) and Crawford (532 MW) stations shut down in September 2012. Average realized fuel cost ($/MWh)3 Average realized gross margin ($/MWh)2 $19.43 $26.34 $18.32 $24.69 $26.85 $11.84 $29.14 $15.09 Q3 11 Q3 12 YTD 11 YTD 12 All-in Average Realized Prices1,3 $46.28 $47.46 $38.18 $39.78 • Total Generation (GWh) • Forced Outage Rate • Capacity Factor • Equivalent Availability • Load Factor • Flat energy price • NI Hub ($/MWh) YTD 11 20,987 5.9% 62% 80% 77.5% $35.30 YTD 12 17,459 4.8% 52.5% 83.5% 62.9% $28.56 Midwest Generation (Illinois) 4,314 MW4 – Four mid-merit facilities Utilize Powder River Basin (PRB) coal Operational Statistics Q3 11 7,957 7.2% 69.8% 89.4% 78.1% $37.33 Q3 12 6,653 5.4% 62.2% 92.5% 67.2% $32.28

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 32 September 30, 2012 Midwest Generation Hedging & Capacity Sales1 Total GWh (NI, AEP/Dayton, and Indiana Hubs) Average price ($/MWh) Coal under contract (millions of tons)3 1 See ―Market Risk Exposures – Commodity Price Risk‖ in EME’s quarterly report on Form 10-Q for complete descriptions and definitions of hedging programs. 2 Change from Q2 for 2012 includes 69 GWh of new hedges. 3 In July 2012 Midwest Generation agreed to sell one million tons of coal scheduled to be delivered in the second half of 2012 in order to better manage coal inventories. This transaction resulted in a $6 million loss the quarter ended September 30, 2012. 2014 Remainder of 2012 2013 Net2 Change From Q2 Net2 Change From Q2 Net2 Change From Q2 2,028 $37.53 4.9 3,615 $36.55 11.1 — — 9.8 (1,610) $(0.71) (4.5) 2,595 $(3.87) 0.5 — — — 4,704 4,650 4,625 3,620 $16.46 $27.73 $125.99 $136.00 (450) (2,430) (700) — $15.67 $7.01 $5.54 — $16.54 $50.40 $147.47 $136.00 October 1, 2012 to May 31, 2013 June 1, 2013 to May 31, 2014 June 1, 2014 to May 31, 2015 June 1, 2015 to May 31, 2016 MW Average Price per MW-day Aggregate Average Price per MW-day MW Price per MW-day RPM Capacity Sold in Base Residual Auction Other Capacity Sales, Net of Purchases

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 33 EME 2006 Illinois CPS Agreement NOx SO2 Construction timeline Fleet-wide average emission rate (lb/mmbtu) Construction timeline Fleet-wide average emission rate (lb/mmbtu) Mercury Construction timeline Fleet-wide average emission rate (lb/GWh) 2012 2013 2014 2015 2016 2017 2018 2019 0.11 Up to $628 million total for large units Waukegan 7, 8 Joliet, Powerton, Will County Waukegan 7 0.008 or 90% reduction Will County 3 Cost included in SO2 spend 2011 Emissions1 ACI $45 million Completed 0.0074 or 86%2 0.17 0.43 0.44 0.41 0.28 0.195 0.15 0.13 0.11 Fleet-wide requirement Unit-specific requirement SNCR $105 million US EPA MATS Deadline 1 Based on tests administered closest to year ended December 31, 2011, and submitted to Illinois EPA for compliance. 2 Actual mercury requirement for 2011 under the CPS was 5 lb/MMacf ACI injection, which has been met. Percent reduction requirement is based on mercury concentration in coal before and after treatment system. Reduction is across all units, including Waukegan 7 and Will County 3, which will require particulate removal upgrades to meet fleet-wide emission and unit-specific requirements. Midwest Generation believes that currently installed ACI and particulate removal equipment is sufficient to achieve or exceed the requirements outlined in the final MATS Rule.

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 34 Midwest Generation Compliance Cost Unit Waukegan 7, 8 689 3,898 13.9% $160 Joliet 6 290 1,675 5.9% $75 Joliet 7, 8 1,036 5,907 21.0% $200 Will County 3, 41 761 3,492 12.4% $194 Powerton 5, 6 1,538 9,184 32.7% $234 Total 4,314 24,156 $628 $235 1 Will County 3 requires particulate removal upgrades in 2015 to comply with the CPS requirements. 2 No decision has been made to retrofit particular units. Capital expenditure forecast provides for large unit retrofits. It is less likely that retrofits will be made to Joliet 6 and the Waukegan Station. Operating Capacity (MW) 2011 Generation (GWh) % of Regional Fleet Total Large Unit Est. Capex ($MM)2 Total Small Unit Est. Capex ($MM)2

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 35 EME Wind Strategy & Financing Refocused Wind Strategy Project Debt Other Recent Wind Developments Wind Project Financing Capacity 1 Includes Storm Lake project (108 MW) that was impaired in the quarter ended December 31, 2011. • Capistrano Wind Partners (CWP) formed February 13, 2012, by EME, TIAA-CREF, CIRI (an Alaskan native corporation). $460 million commitment for wind development:  Operating projects transferred – Cedro Hill, Texas (150 MW) and Mountain Wind I and II, Wyoming (141 MW) – EME received $242 million in March 2012  Projects to be transferred after completion – Broken Bow I, Nebraska (80 MW) and Crofton Bluffs, Nebraska (40 MW) – EME expects to receive $140 million upon transfer of completed projects  EME retains an economic interest and will continue to operate and consolidate projects • 700 MW development pipeline • New wind projects to be developed or acquired only with third-party capital • Continuing Big Sky vendor dispute regarding timing of repayment of $206 million in project debt; no recourse to EME • Broken Bow I, Nebraska (80 MW) and Crofton Bluffs, Nebraska (40 MW) expected completion in fourth quarter 2012 • 575 MW not financed:  387 MW contracted1  188 MW merchant – Goat Wind, Texas (150 MW), Lookout, Pennsylvania (38 MW)

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 36 EME Capital Expenditures Midwest Generation Environmental expenditures3 Plant capital expenditures Walnut Creek Project4 Renewable Energy Projects Capital & construction Turbine commitments Other capital expenditures Total 2013 1 2011 expenditures shown on accrual basis. 2 Includes actual expenditures plus estimated remaining for 2012. 3 Projected expenditures to retrofit Powerton Units 5 and 6, Joliet Units 7 and 8, and Will County Units 3 and 4. No decisions have been made to retrofit particular units. 4 Total project costs are estimated to be $611 million. Capital expenditures in the above table exclude $72 million of interest and expenses during construction, financing costs, and costs incurred before 2011. September 30, 2012 ($ millions) $82 27 269 267 8 7 $660 $112 50 63 1 — 19 $245 $26 8 206 112 — 19 $371 2013 20111 20122 $311 16 — 2 — 15 $344 2014

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 37 Reconciliation to Earnings EMG1 – Adjusted EBITDA Q4 09 Q1 11 Earnings Addback (Deduct): Discontinued operations Income from continuing operations Interest expense Interest income Income taxes (benefits) Depreciation and amortization EBITDA1 Production tax credits Addback: Gain on sale of Beaver Valley Loss on sale/disposal of assets Adjusted EBITDA September 30, 2012 ($ millions) 1 Earnings are attributable to Edison Mission Group and include impact of Edison Capital. 2 See Use of Non-GAAP Financial Measures. Q3 11 3 12 YTD 11 YTD 12 $33 (15) 18 82 0 (11) 72 $161 10 — — $171 $(137) 76 (61) 83 (1) (15) 67 73 12 (67) 2 $20 $(331) 129 (202) 253 (2) (169) 202 82 48 (67) 7 $70 $(17) 3 (14) 243 (3) (102) 213 $337 47 — 8 $392

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 38 $997 155 120 $1,272 $390 12 $402 $699 182 126 $1,007 443 15 $458 $253 47 40 $340 183 4 $187 17,459 $699 2 (6) $695 $39.78 $443 (2) (10) $431 $24.69 20,987 $997 1 (2) $996 $47.46 $390 (6) 0 $384 $18.32 6,653 $253 5 (4) $254 $38.18 $183 2 (10) $175 $26.34 EME Other Non-GAAP Reconciliations Reconciliation of Midwest Generation Operating Revenues and Fuel Costs to All-in Average Realized Price/MWh and Average Realized Fuel Cost/MWh Generation (GWh) Operating revenues Less: Unrealized (gains) losses Other revenues Realized revenues All-in average realized price/MWh Fuel costs Add back: Unrealized gains (losses) Cost of coal sales Realized fuel costs Average realized fuel cost/MWh 7,957 $366 3 (1) $368 $46.28 $157 (4) 0 $153 $19.43 Q3 11 Q3 12 Midwest Generation Operating revenues Midwest Generation Renewable projects Other revenues Segment revenues as reported Fuel Costs Midwest Generation Other revenues Segment revenues as reported Reconciliation of Midwest Generation Operating Revenues to Segment Revenues and Fuel Costs Q3 11 Q3 12 $366 44 27 $437 $157 4 $161 ($ millions) YTD 11 YTD 12 YTD 11 YTD 12

Exhibit 99.2 EDISON INTERNATIONAL® Leading the Way in Electricity SM November 1, 2012 39 Edison International’s earnings are prepared in accordance with generally accepted accounting principles used in the United States and represent the company’s earnings as reported to the Securities and Exchange Commission. Our management uses core earnings and EPS by principal operating subsidiary internally for financial planning and for analysis of performance. We also use core earnings and EPS by principal operating subsidiary when communicating with analysts and investors regarding our earnings results and outlook, to facilitate the company’s performance from period to period. Core earnings is a Non-GAAP financial measure and may not be comparable to those of other companies. Core earnings and core earnings per share are defined as GAAP earnings and basic earnings per share excluding income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings. GAAP earnings refer to net income attributable to Edison International common shareholders or attributable to the common shareholders of each subsidiary. EPS by principal operating subsidiary is based on the principal operating subsidiaries’ net income attributable to the common shareholders of each subsidiary, respectively, and Edison International’s weighted average outstanding common shares. The impact of participating securities (vested stock options that earn dividend equivalents that may participate in undistributed earnings with common stock) for each principal operating subsidiary is not material to each principal operating subsidiary’s EPS and is therefore reflected in the results of the Edison International holding company, which we refer to as EIX parent company and other. EBITDA is defined as earnings before interest, income taxes, depreciation and amortization. Adjusted EBITDA includes production tax credits from EME’s wind projects and excludes amounts from gain on the sale of assets, loss on early extinguishment of debt and leases, and impairment of assets and investments. Our management uses Adjusted EBITDA as an important financial measure for evaluating EME which represents substantially all of the EMG business segment. The average realized energy price and average realized fuel cost is a non-GAAP performance measure since such statistical measures exclude unrealized gains or losses recorded as operating revenues and unrealized gains or losses recorded as fuel expenses. Management believes that the average realized energy price and average realized fuel cost is more meaningful for investors as it reflects the impact of hedge contracts at the time of actual generation in period-over- period comparisons or as compared to real-time market prices. A reconciliation of Non-GAAP information to GAAP information, including the impact of participating securities, is included either on the slide where the information appears or on another slide referenced in this presentation. Use of Non-GAAP Financial Measures