8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 29, 2008

EDISON INTERNATIONAL

(Exact name of registrant as specified in its charter)

CALIFORNIA	001-9936	95-4137452
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)

2244 Walnut Grove Avenue

(P.O. Box 800)

Rosemead, California 91770

(Address of principal executive offices, including zip code)

626-302-2222

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

This current report and its exhibit include forward-looking statements. Edison International based these forward-looking statements on its current expectations and projections about future events in light of its knowledge of facts as of the date of this current report and its assumptions about future circumstances. Forward-looking statements are subject to various risks and uncertainties that may be outside the control of Edison International and its subsidiaries. Edison International has no obligation to publicly update or revise any forward-looking statements, whether due to new information, future events, or otherwise. This current report should be read with Edison International’s Annual Report on Form 10-K for the year ended December 31, 2007 and subsequent Quarterly Reports on Form 10-Q.

Item 7.01 Regulation FD Disclosure.

Members of Edison International management will use the presentation attached hereto as Exhibit 99.1 in planned meetings with institutional investors and analysts during September 2008. This presentation will also be posted on Edison International’s web site as a reference on business performance and strategies for investors.

The information furnished in this Item 7.01 and Exhibit 99.1 shall not be deemed “filed” for purposes of the Securities Exchange Act of 1934, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933.

Item 9.01 Financial Statements and Exhibits.

(c) Exhibits

See the Exhibit Index below.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

EDISON INTERNATIONAL

                (Registrant)

/s/ Linda G. Sullivan

Linda G. Sullivan

Vice President and Controller

Date: August 29, 2008

EXHIBIT INDEX

Exhibit No.	Description
99.1	Edison International September 2008 Business Update Handout

EX-99.1

Exhibit 99.1

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Business Update

September 2008

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Forward-Looking Statements

Statements contained in this presentation about future performance, including, without limitation, earnings, asset and rate base growth, load growth, capital investments, 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. Important factors that could cause different results are discussed under the headings “Risk Factors” and “Management’s Discussion and Analysis” in Edison International’s 2007 Form 10-K and other reports filed with the Securities and Exchange Commission are available on our website: www.edisoninvestor.com. 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.

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What’s New Since Our May 2008 Update

Updated Information

2Q 2008 results and forward looking forecasts as appropriate

Updated SCE customer and load growth forecast (p. 9)

EMG environmental compliance (p. 22)

EMMT scope (p. 23)

EMG development

– Wind (pp. 24-26)

– Solar (p. 27)

– Natural gas (p. 28)

Additional Topics

Strategic overview: five business priorities (p. 4)

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Strategic Overview

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Edison International Value Drivers

EIX Integrated Platform

SCE Value Drivers

Proposed $19.9 billion, 5-year capital investment plan1

49%—Distribution

28%—Transmission

13%—Generation

10%—SmartConnect™ & Solar Rooftop

Energy Efficiency programs represent a new earnings opportunity

Strong regulatory framework

Three-year forward rate-setting

Multi-year cost of capital mechanism

Procurement cost recovery mechanisms

Financial performance

Earning assets expected to grow 12%+ annually from 2007—2012

EMG Value Drivers

Low-cost coal generation portfolio

Adjusted EBITDA has exceeded $1 billion annually2

Favorable capacity market trends

Operational and marketing/hedging capabilities

Experienced and value-adding trading ? capability In and around our asset base

Long-term environmental plan for Midwest Generation and Homer City

Prudent allocation of capital to allow for:

Hedging collateral

Financial flexibility

Diversify and grow generation portfolio

Emphasize renewables and natural gas

Focus on organic growth

1 Subject to timely receipt of permitting, licensing and regulatory approvals. See “SCE Capital Investment Forecast” (page 10) for further information.

2 See use of Non-GAAP Financial Measures at the end of this presentation for additional information on EBITDA and Adjusted EBITDA.

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Execute on Business Priorities

Focus on Superior Execution of

5 Main Business Priorities

Obtain Good Regulatory Decisions

Manage Our Large Construction Program Well

Diversify EMG’s Coal Concentration

Meet Environmental Challenges

Deliver On Our Wind Development Pipeline

Realizing our substantial growth potential will require superior execution

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Financial Strategies

Funding Growth Investments

Southern California Edison

Operating cash flow and financing

Edison Mission Energy

Cash on hand, operating cash flow and project debt

Credit

Objectives1

Southern California Edison

A rating metrics (current: S&P BBB, Fitch A, Moody’s A3)

Edison Mission Energy

BB rating metrics (current: S&P & Fitch BB-, Moody’s B1)

Dividend

Policy

Targeting annual dividend increases

Dividend increases balanced with growth investments

Parent financing capacity supports financial strategies

1 Senior unsecured credit ratings shown.

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2008 Earnings Guidance

Guidance Reconciliation: Core Earnings Per Share to GAAP Earnings Per Share1

Core and GAAP earnings per share guidance reaffirmed as of

8/8/2008

EIX core earnings per share $ 3.61 — $ 4.01

Non-core items —

EIX GAAP earnings per share $ 3.61 — $ 4.01

Core and GAAP earnings per share guidance elements reaffirmed as of

8/8/2008

SCE $ 2.18 — $ 2.28

EMG $ 1.57 — $ 1.87

EIX parent company and other ($0.14)

Total guidance elements $ 3.61 — $ 4.01

Note: Guidance excludes certain items shown at right

Updated Guidance Factors

EIX

Continue to see 2008 core earnings around the high end of the guidance range

SCE

11.5% Return on Equity

Includes potential Energy Efficiency earnings of $0.08 per share

EMG

Forward hedge positions and prices as of 7/31/08

EMMT pre-tax trading margin $92M for six months ended 6/30/08

Lower pre-tax earnings from EMG’s Sycamore and Watson projects ($60—$70M reduction)

Excluded from Guidance

Discontinued operations and non-core items

Potential impact of preliminary IRS settlement

Possible impairment of up to $48M for NOx allowances purchased by EMG for CAIR compliance program

1 See Use of Non-GAAP Financial Measures in appendix. The expected impact of participating securities is $(0.05) per share for 2008 guidance and is included in EIX parent company and other. GAAP earnings per share refers to basic earnings per share.

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Southern California Edison (SCE)

An Investor-Owned Electric Utility

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SCE System

Largest electric utility in California

13 million residents

4.8 million customer accounts

50,000 square-mile service area

Earnings model

SCE earnings are decoupled from demand

Earnings driven by CPUC and FERC approved rate of return on earning asset base

Cost inflation forecast included in general rate case

Customer and load growth

2008 new connections forecast (~48,500) represents just over 60% of five-year average and a decline of 28% from new connections in 2007

2008 peak demand expected to grow to over 23,500 MW, 1% above 23,303 MW peak demand in 2007

California and SCE Service Territory

SCE Service Territory

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SCE Capital Investment Forecast

$19.9 Billion Over 5 Years

$ Billions $5

$4 $3 $2 $1 $0

$2.9

$4.1

$4.5

$4.6

$3.8

2008 2009 2010 2011 2012

By Classification

$ %

Solar Rooftop Program 0.85 4

Edison SmartConnect™ 1.25 6

Generation 2.50 13

Transmission 5.50 28

Distribution 9.80 49

Total1 19.90 100

By Proceeding Type

$ %

CPUC Rate Cases 11.80 59

CPUC Project Specific 2.60 13

FERC Rate Cases 5.50 28

Total1 19.90 100

In 2008, SCE anticipates regulatory approval on a substantial portion of its capital spending program

1 Subject to timely receipt of permitting, licensing and regulatory approvals. Forecast as of March 2008 and includes $692 million of capital spending for DPV2, the majority of which is expected to occur in 2009 and 2010. The Arizona Corporation Commission (ACC) denied approval of the DPV2 project, resulting in a minimum two-year delay. SCE initiated pre-filing activities with the FERC and continues to work with the ACC on acceptable alternatives.

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SCE Rate Base Forecast (2007-2012)1

$ Billions $25

$20 $15 $10 $5 $0

1 2 + % Compound Annual Growth

$11.7

$12.7

$15.5

$18.3

$21.3

$23.6

2007 2008 2009 2010 2011 2012

Superior execution of capital expenditure program and continued regulatory support could double SCE’s earning asset base by 2012

1 Includes impact of 2006 CPUC and 2006 FERC GRC decisions and forecasted rate base for FERC (2007-2012) and CPUC (2009-2012) which are subject to timely receipt of permitting, licensing and regulatory approvals; includes estimated impacts of the November 15, 2007 FERC incentives decision allowing construction work-in-progress (CWIP) recovery in rate base and the Economic Stimulus Act of 2008. Forecast is as of March 2008 and includes $692 million of capital spending for DPV2, the majority of which is expected to occur in 2009 and 2010. The Arizona Corporation Commission (ACC) denied approval of the DPV2 project which has resulted in a minimum two-year delay of the project. SCE has initiated pre-filing activities with the FERC and is continuing to work with the ACC on acceptable alternatives.

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SCE Transmission Investment Program

Tehachapi transmission line to interconnect up to 4,500 MW of generation

New transmission needed to strengthen system reliability and access economical power

NEVADA CALIFORNIA

Tehachapi Service SCE

Windhub

Territory

Antelope Palmdale

Vincent ARIZONA Santa Clarita Pardee RanchoVista Mira Loma Devers Phoenix Los Angeles Santa Ana Valley Palm Springs Verde Palo

San Diego

Tehachapi Segments 1-3 500kV DPV2 & Rancho Vista 500kV

Tehachapi Segments 4-11 500kV

2008-2012 FERC

Project Name Phase In-Service ($ Millions)1 Adders (bps)

Renewables

Tehachapi Segments 1-3 Construction2 2009-2010 328 175

Tehachapi Segments 4-11 Licensing 2011-2013 1,742 175

Other Projects Licensing Various 933 —

Total Renewables 3,003

Reliability

Rancho Vista Substation Construction 2009 192 125

Other Projects Various Various 1,589 —

Total Reliability 1,781

Economics

DPV2 Licensing2 2011 692 175

Grand Total 5,476

FERC earning asset base is expected to more than double from 10% of rate base in 2007 to over 20% by 2012

1 Subject to timely receipt of permitting, licensing, and regulatory approvals. Forecast is as of February 2008.

2 Petitions to Modify CPUC decisions were submitted in May, 2008 for DPV2 to approve construction of the California portions first, and in July, 2008 for Tehachapi 1-3, to update costs included here. Tehachapi 1-3 in-service date has moved to June 2009, with Segment 3B to early 2010 (no change to total project cost).

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SCE SmartConnectTM Program

Meter Installation Timeline1

2008 2009 2010 2011 2012

Annual Capital Spending ($MM) $100 $350 $350 $300 $145

Cumulative Meters (MM) – 1.4 3.0 4.6 5.3

Application filed July 2007 to deploy to 5.3 million residential and small commercial customers between 2008 – 2012

On August 19, received CPUC Proposed Decision (PD) approving program

Estimated total project cost is $1.7 billion (approximately $1.25 billion is capital cost to be included in rate base)1

Edison SmartConnectTM has the potential to reduce peak power consumption by as much as 1,000 MW and reduce GHG emissions by 365,000 metric tons per year

Integrate Homes with the Utility Circuit

Integrate Smart Appliances with the Home

SCE is leading the way in advanced metering infrastructure

1 Subject to CPUC approval.

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SCE Energy Efficiency Earnings Opportunity

CPUC Approved Energy Efficiency (EE) Shareholder Incentive Mechanism

2006-2008 EE Cycle

Year 2006 2007 2008

2009-2011 EE Cycle

2009 2010 2011 2012 2013

Potential Earnings Profile by Year2

65% of 2006-2007 earnings opportunity1

65% of 2008 earnings opportunity

35% of 2006-2008 earnings opportunity plus true-up

65% of 2009-2010 earnings opportunity1

65% of 2011 earnings opportunity

35% of 2009-2011 earnings opportunity plus true-up

SCE, the national leader in energy efficiency, is targeting $1.2 billion in net customer savings and an earnings opportunity of up to ~$146 million (pre-tax) for 2006-20083

1 Based upon September 20, 2007 and January 31, 2008 decisions released by the CPUC. There is no assurance of earnings. If CPUC approves, SCE estimates to record a progress payment in the range of $41-$49 million in 4Q08 for the first two years of the program cycle and expects to collect the payment in 2009 rates.

2 Assumes SCE achieves all EE goals and delivers customer benefits of approximately $1.2 billion. Cash expected to be received in the following year.

3 The $146 million earnings opportunity (pre-tax) for 2006-2008 EE cycle. January 2008 modifications incorporate an update to the effective useful life of residential compact fluorescent lights. If the draft CPUC effective useful life study is adopted in its current form, SCE’s earnings opportunity would decrease to approximately $124 million.

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SCE Solar Rooftop Program

Install 250 MW of thin-film solar photovoltaic (PV) generation on commercial rooftops

– 1-2 MW average project size

– $875 million 1 capital spending program

Initial 2 MW start-up in Fontana

– Expected operational September 2008

– First Solar awarded PV contract

SCE requested authority to recover costs incurred during regulatory approval process to facilitate 2008 program launch

SCE’s proposed rooftop solar program will help advance California public policy and help build scale for the large rooftop photovoltaic solar market

1 Subject to CPUC approval. Direct capital forecast in 2008 dollars (2008-2013).

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Constructive Regulatory Environment

What’s Changed Since the Power Crisis

Advance approval of annual procurement plans for purchased power

Trigger mechanism for fuel and purchased power cost recovery

Forward-looking rate-making includes expected cost inflation

State support for reliable electric system infrastructure

Benefits to Customers and Investors

Upfront review of utility purchasing decisions through a defined procurement plan

Better matching of revenues and cash expenditures for fuel and purchased power costs with predetermined trigger mechanisms for recovering higher costs

Three-year process based on forecast expenses, capital spending and asset base increases between rate cases

Regulatory decisions address emerging issues (such as adding peaking capacity for 2007 summer season) and opportunities (new energy efficiency program and incentives for utility renewable energy investment)

California’s regulatory framework supports growth and reliability needs, while longstanding decoupling policies mitigate risks of volatile commodity prices and economic changes

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Edison Mission Group (EMG)

A Competitive Power Generation Company

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EMG’s Business Platform

Status at June 30, 2008

70

95 180 100

258 241 145 1,884 200 38 29 53 515 520 5,471 40

89 305 192 964 479 95

90 299 1,140 1,070

241 470

85

Current Operating Platform

MW %

Coal 7,395 77

Natural Gas / Other1 1,492 16

Renewables 695 7

9,582 100

Under Construction & Development Pipeline

MW

Natural Gas2 479 Renewables3 5,450

EMG is focusing on superior execution to deliver on its wind development pipeline and diversify its coal concentration.

1 Other includes Doga in Turkey (144 MW) and Huntington biomass (9 MW)—not shown on map.

2 Contract award subject to regulatory approval with planned on-stream date June 2013.

3 Owned or under exclusive agreement.

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EMG Coal-Fired Fleet

Midwest Generation (Illinois)

5,776 MW – Six mid-merit facilities and peakers acquired in 1999

Burns Powder River Basin (PRB) coal

Rail under contract through 2011

Operational Statistics: 2006 2007 YTD 20083

Total Generation (GWh) 28,898 29,961 15,203

Load Factor 74.1% 80.4% 82.2%

Equivalent Availability 79.3% 75.8% 77.5%

Homer City (Pennsylvania)

1,884 MW – Three base-load units acquired in 1999

Burns Northern Appalachian (NAPP) coal

Coal largely sourced locally and delivered by truck

Operational Statistics: 2006 2007 YTD 20083

Total Generation (GWh) 12,286 13,649 5,442

Load Factor 90.7% 92.4% 88.6%

Equivalent Availability 81.9% 89.4% 74.6%

All-in Average Realized Prices1 $60 $53

$46 $47 $40 $40

$34 $34

$/MWh $20

$12 $13 $13 $0 2005 2006 2007

All-in Average Realized Prices1

$60 $56

$46 $49

$40 $34 $26

$/MWh $25

$20

$21 $23 $22 $0 2005 2006 2007

Average realized gross margin ($/MWh)2 Average fuel and emission costs ($/MWh)

1 The all-in average realized price reflects the average price for sale of energy, capacity and ancillary services sold into the market, including the effects of hedges, real-time and day ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenues less (plus) unrealized SFAS No. 133 gains (losses) by (ii) generation. Operating revenues includes capacity sales and sales under load services requirements contracts.

2 Average realized gross margin is equal to all-in average realized prices less average fuel and emission costs.

3 Year-to-date through June 30, 2008.

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EMG Hedge Program Status

Status at June 30, 2008

Remainder of

2008 2009 2010 2011

Midwest Generation

Energy Only Contracts

Northern Illinois & AEP/Dayton Hubs (GWh) 5,427 11,378 7,961 203

Average Price ($/MWh) $61.30 $66.53 $67.39 $76.20

Load Requirement Services Contracts

Northern Illinois Hub (Estimated GWh)1 2,220 1,571 — —

Average Price NiHub ($/MWh)2 $64.37 $63.65 — —

Total estimated GWh hedged 7,647 12,949 7,961 203

Coal under contract (in millions of tons) 10.3 11.7 11.7 —

Hedges Added During 2Q 08 (GWh) — 3,686 4,489 203

Homer City

Total estimated GWh hedged 3,636 4,096 2,654 —

Average Price ($/MWh)3 $60.84 $82.84 $90.52 —

Coal under contract (in millions of tons)4 3.2 4.5 0.4 0.1

Hedges Added During 2Q 08 (GWh) — 1,229 1,632 —

1 Power sold is a portion of the retail load of the purchasing utility and can vary significantly. Retail load depends upon a number of factors, and the actual load will vary from that used for the above estimate, and the amount of variation may be material.

2 The average price per MWh, subject to a seasonal price adjustment, represents the sale of a bundled product that includes, but is not limited to, energy, capacity and ancillary services. Midwest Generation will incur charges from PJM as a load-serving entity. The average price per MWh is not comparable to the sale of power under an energy only contract. The average price per MWh represents the sale of the bundled product based on an estimated customer load profile.

3 The average price/MWh for Homer City’s hedge position is based on PJM West Hub prices. As a result of transmission congestion in the PJM, actual energy prices at the Homer City busbar have been lower than those at the PJM West Hub.

4 At June 30, 2008, there are options to purchase additional coal of 1.7 million tons in 2010 and 1.2 million tons in 2011.

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EMG Capacity Sales

Status at June 30, 2008

July 1, 2008 — May 31, 2009 Jun 1, 2009 — May 31, 2010 Jun 1, 2010 — May 31, 2011 Jun 1, 2011 — May 31, 2012

Midwest Homer Midwest Homer Midwest Homer Midwest Homer

Megawatts except price per MW-day Generation City Generation City Generation City Generation City

Installed Capacity 5,776 1,884 5,776 1,884 5,477 1,884 5,477 1,884

Less: Net capacity held due to load

requirement services contracts,1

and retained for outages (1,918) (159) (447) (214) (548) (71) (895) (113)

Net Capacity Available for Sale 3,858 1,725 5,329 1,670 4,929 1,813 4,582 1,771

Fixed Price Capacity Sales

RPM Auction Process

Net Capacity Sold 2,978 2 820 2 4,614 1,670 4,929 1,813 4,582 1,771

Price per MW-day $122.36 2 $111.92 2 $102.04 $191.32 $174.29 $174.29 $110.00 $110.00

Non-unit Specific Capacity Sales

Net Capacity Sold 880 715

Price per MW-day (Net) $64.35 $71.46

Variable Capacity Sales

Third Party Transaction

Capacity 905

Expected price per MW-day3 $65.76

Total Capacity Sold 3,858 1,725 5,329 1,670 4,929 1,813 4,582 1,771

Average Price per MW-Day $109.13 $87.70 $97.94 $191.32 $174.29 $174.29 $110.00 $110.00

1 Load requirements services contracts include energy, capacity and ancillary services.

2 The original price of $111.92 was affected by Midwest Generation’s participation in a supplemental RPM auction during the first quarter of 2008, which resulted in purchasing certain capacity amounts at a price of $10 per MW-day, thereby reducing the aggregate forward capacity sales for this period and increasing the effective capacity price to $122.36.

3 Actual contract price is a function of NYISO capacity auction clearing prices in June 2008 through July 2008 and forward over-the-counter NYISO capacity prices on June 30, 2008 for August 2008 through May 2009.

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EMG Environmental Compliance

MWG Compliance Plan1

Phase I – Mercury Reductions

90% mercury removal by 2015

Installation of Activated Carbon Injection (ACI) technology by July 2009

Completed mercury controls at Waukegan, Fisk, Crawford

Estimated cost $60 million

Phase II – NOx Reductions

Emissions of .11 lbs. per million Btus by 2011 (66% reduction)

Installation of primarily Selective Catalytic Reduction (SCR) systems by the end of 2011

Estimated cost $450 million

Phase III – SO2 Reductions

Emissions of .11 lbs. per million Btus by 2019, with interim step-down (78% reduction)

Flue Gas Desulfurization (FGD) technology

Estimated cost $2.2 – $2.9 billion

Homer City Compliance Plan

PA State Implementation Plan for CAMR and CAIR adopted

Homer City expects to comply with the 2010 phase of mercury requirements by installing ACI on Units 1

& 2

Clean Air Interstate Rule

In July 2008, D.C. Circuit Court of Appeals vacated the US EPAs CAIR and remanded it to the US EPA2

We are evaluating the potential impact, including whether $48 million in annual NOx emission allowances purchased to comply with CAIR are impaired

EMG is in the process of selecting a final EPC contractor for Powerton environmental upgrades. EMG expects to update environmental capital expenditure estimates in 2008.

1 Cost estimates are in 2006 dollars.

2 The Illinois Plants and Homer City facilities continue to be governed by state rules as well as the existing “SIP Call” ozone season NOx cap-and-trade program.

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Edison Mission Marketing & Trading (EMMT)

Markets energy and capacity of merchant generation fleet

Hedges key power-related risks such as forward electricity prices

Typically a rolling 24 to 36 month hedging program

Target hedge-neutral position for prompt year with lesser percentages hedged in the out years

Trades a proprietary book in markets where it is active in merchant generation

Primarily transmission-related transactions

Largely in eastern markets

Enters into load service requirements contracts with local utilities and hedges related to energy price risk

Controls on types and sizes of exposures

VaR; EaR; stress and scenario testing; volumetric, duration, and credit limits

EMMT Trading Margin (pre-tax)1

$ Millions $250

$200 $150 $100 $50 $0

$195

$143 $130

$92

$34 $23

2003 2004 2005 2006 2007 YTD June 2008

EMMT provides significant incremental income

1 Income from energy trading represents gains recognized from trade price changes. The overhead cost of energy trading is excluded.

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Wind Energy Development Strategy & Portfolio

Wind Energy Development Strategy

Strategic importance to growth plan

Contributes to portfolio diversification

Objective is to attain national scope and leadership scale

Wind energy provides attractive opportunities

Growing RPS requirements

Production tax credits and accelerated depreciation

Mainly long-term contracts for output

Wind Project Portfolio & Development Pipeline

Projects1 No. of Projects MW

In-Service 16 695

Under Construction 8 390

Total Projects 24 1,085

Development Pipeline2 34 5,060

Turbines

Purchased and under option 1,061

1 Data as of June 30, 2008.

2 Development pipeline includes projects owned or under exclusive agreements.

MW by Manufacturer

Projects In-Service & Under Construction

Zond 109

Suzlon 439

Siemens 161

Clipper 50

Vestas Mitsubishi

86 240

Turbines Purchased & Under Option

300 GE Suzlon 305

Clipper Mitsubishi 127 329

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EMG Diversifying With Wind

Arizona

Pipeline 1,140 MW

Wyoming

Construction 141 MW

Pipeline 100 MW

Utah

Construction 19 MW

Pipeline 70 MW

Oklahoma

Operating 95 MW

Construction 19 MW

Pipeline 280 MW

Nevada

Pipeline 515 MW

New Mexico

Operating 90 MW

Pipeline 1,070 MW

Texas

Operating 241 MW

Construction 70 MW

Pipeline 400 MW

Iowa

Operating 145 MW

Pipeline 200 MW

Minnesota

Operating 95 MW

Construction 50 MW

Pipeline 130 MW

Nebraska

Construction 53 MW

Illinois

Pipeline 520 MW

Maryland

Pipeline 85 MW

Wisconsin

Pipeline 100 MW

New York

Pipeline 258 MW

West Virginia

Pipeline 192 MW

Pennsylvania

Operating 29 MW

Construction 38 MW

EMG Wind Portfolio1

MW

Operating 695

Construction 390

1,085

Pipeline 5,060

Turbines (not shown) 1,061

1 Owned or under exclusive agreement at June 30, 2008. Turbines purchased or committed to support development pipeline.

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Wind Construction Highlights

Project State MW PPA Date Milestones

Recently Completed

Mountain Wind I Wyoming 61 Yes July 2008

Spanish Fork Utah 19 Yes July 2008

In-Service 2008 (Target)

Mountain Wind II Wyoming 80 Yes September 2008 Commissioning first turbines

Lookout Pennsylvania 38 No October 2008 Awaiting transmission connection

Elkhorn Ridge Nebraska 80 Yes December 2008 On schedule

Buffalo Bear Oklahoma 19 Yes December 2008 On schedule

In-Service 2009 (Target)

Goat Mountain Phase II Texas 70 Yes Early 2009 On schedule

High Lonesome New Mexico 100 No Mid 2009 On schedule

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EMG Solar Program

EMG is seeking to deploy commercial solar power projects

Large-scale (20-500 MW per site)

Ground mounted

Connected to transmission grid

Primary search area:

California

Nevada

Arizona

New Mexico

Have identified over 30 sites for potential solar projects

Focus on high solar insolation areas

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EMG U.S. Natural Gas Fired Plants

Size (MW)

Name EMG Share

Kern River 150

Midway-Sunset 113

Sycamore 150

Watson 189

Coalinga 19

Mid-Set 19

Salinas River 19

Sargent Canyon 19

March Point 70

Sunrise 286

1,034

Current growth opportunities

Walnut Creek, CA – Awarded 10-year power purchase agreement with SCE for 479 MW – Online June 1, 2013

Sun Valley, CA opportunity (500 MW) in permitting and engineering stage

Potential acquisitions of assets or portfolios

Will be selective and disciplined

Complement marketing and trading skills

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EMG Capital Expenditures

Estimated Expenditures1

Projects Under Construction Wind Turbine Commitments Plant/Corporate Capex Plan $ Millions Environmental Plan $1,000

$786 $800 $713 $634 $600

$400

$200

$0

Jul.—Dec. 2009 2010 2008

Total $2,133 Million

Estimated Expenditures (2008 – 2010)

Additional growth opportunities

Additional wind turbines

Balance of plant costs for purchased wind turbines

Homer City will comply with 2010 phase of mercury requirements

Estimated Expenditures After 2010

Midwest Generation environmental spending plan

Evaluating FGD installation at Homer City

Additional growth opportunities

1 EMG expects to make substantial investments in new projects during the next three years. As of June 30, 2008, EMG had a development pipeline of potential wind projects with an estimated installed capacity of approximately 5,000 MW (the development pipeline represents potential projects for which EME either owns the project rights or has exclusive negotiation rights). Completion of these projects is dependent upon a number of items, and there is no assurance that the projects included in the development pipeline currently or added in the future will lead to the successful completion of a wind project.

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Liquidity Profile

Available Liquidity at June 30, 2008

EIX Parent

Sources ($ in Millions) SCE EMG Co. & Other Total1

Credit Facility $ 2,500 $ 1,100 $ 1,500 $ 5,100

Credit Facility (availability) $ 1,503 $ 968 $ 1,500 $ 3,971

Cash & short term investments2 187 805 91 1,083

Available Liquidity $ 1,690 $ 1,773 $ 1,591 $ 5,054

1 Total amounts do not imply any credit support among entities except as specified in each credit facility.

2 SCE amount includes $112 million held by SCE’s consolidated variable interest entities.

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Our Shareholder Value Proposition

Attractive business portfolio and growth opportunities

Southern California Edison

Demonstrated need for utility infrastructure investments

Among the best domestic electric utility growth platforms

Leadership in environmental and alternative energy programs (energy efficiency, renewable energy, advanced technologies)

Edison Mission Group

Favorable market conditions for unregulated generation portfolio

Strong growth pipeline led by renewable investments

Commitment to long-term shareholder value creation

Incentive compensation and stock ownership guidelines consistent with shareholder interests

Edison people committed to excellence in safety and customer service

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EMG Adjusted EBITDA

Reconciliation to Net Income ($ Millions) 2006 2007

Net income $ 432 $ 410

Addback (Deduct):

Discontinued operations (97) 2

Income from continuing operations 335 412

Interest expense 409 323

Interest income (118) (101)

Income taxes 154 170

Depreciation and amortization 157 172

EBITDA1 937 976

Production tax credits2 17 28

Discrete items:

Gain on sale of assets (22) (1)

Loss on early extinguishment of debt 146 241

Adjusted EBITDA $ 1,078 $ 1,244

1 See Use of Non-GAAP Financial Measures for additional information on EBITDA and Adjusted EBITDA.

2 Production tax credits (PTC) are after-tax.

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Use of Non-GAAP Financial Measures

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 as primary performance measurements when communicating with analysts and investors regarding our earnings results and outlook, as it allows us to more accurately compare the company’s ongoing performance across periods. Core earnings exclude discontinued operations and other non-core items and are reconciled to basic earnings per common share.

EPS by principal operating subsidiary is based on the principal operating subsidiary net income 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. EPS and core EPS by principal operating subsidiary are reconciled to basic earnings per common share.

EBITDA is defined as earnings before interest, income taxes, depreciation and amortization. Adjusted EBITDA includes production tax credits from EMG’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 EMG.

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 the presentation.

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