Exhibit 99.1

Leading the Way in Electricity SM

Business Update

November 2007

November 2, 2007

EDISON INTERNATIONAL®

Leading the Way in Electricity SM

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 2006 Form 10-K and subsequent reports filed with the Securities and Exchange Commission and 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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Strategic Overview

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Edison International Value Drivers

EIX Integrated Platform

SCE Value Drivers

Strong customer and load growth

Tight system reserve margins keep focus on power procurement Energy Efficiency programs represent a new earnings opportunity Proposed $17 billion, 5-year capital investment plan1

51%—Expand and strengthen distribution system

25%—New transmission for system reliability and renewables

16%—San Onofre steam generators and small generation units (“Peakers”)

8%—Edison SmartConnectTM metering program

Strengthened regulatory framework

Three-year forward rate-setting

Cost of capital

Procurement cost recovery mechanisms Financial performance

Earning assets expected to grow 12%+ annually from 2006—2011

EMG Value Drivers

Low-cost coal generation portfolio

Adjusted EBITDA exceeds $1 billion annually2 Favorable capacity market trends Operational and marketing/trading capabilities

Focus on optimizing merchant margins

Experienced/value-added trading capability Debt refinanced at attractive terms Effective allocation of cash

New generation investments

Hedging collateral

Phased environmental compliance Diversify and grow the generation portfolio

Focus on development of non-coal projects with long-term contracts, regional diversity

Emphasize renewables, natural gas, IGCC

1 Subject to timely receipt of permitting, licensing and regulatory approvals. See SCE Growth Driver-Investment slides for further information.

2 See Edison Mission Group – adjusted EBITDA in appendix for reconciliation to net income. 2007 adjusted EBITDA calculation based on mid-point of EMG guidance range.

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Our Business Portfolio

Edison International

Revenue1	$12.6
Operating Cash Flow1	$3.6
Generation Capacity (MW)	14,799
Market Capitalization	$18.5

Southern California Edison

Revenue	$	10.3
Operating Cash Flow		$2.6
Generation Capacity (MW)	5,299
Population Served (MM)		13+

Edison Mission Group

Revenue $2.3 Operating Cash Flow $1.2 Generation Capacity (MW) 9,500 Wind Pipeline (MW) ~ 3,000

1 Reflects inter-company eliminations.

Note: Financial data is for the year ended December 31, 2006; capacity and wind pipeline data is as of September 30, 2007, and market capitalization is as of October 26, 2007. Dollar amounts in billions, population served in millions. Edison Mission Group includes Edison Mission Energy and Edison Capital.

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Our Value Proposition

Strong utility platform with earning assets targeted for 12%+ annual growth

Competitive generation business with low-cost coal portfolio and solid development pipeline

Visible earnings and cash flow growth Valuable business position

Increasing capacity values for coal-fired assets

Attractive and sustainable growth investment opportunities Earnings growth and financial flexibility support dividend growth

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Growth Strategies

Southern California Edison

Driven principally by rate base investment growth Investments emphasize:

Transmission – system reliability, renewables mandates Distribution – system reliability, demand growth Generation – meeting peak system demand, demand growth and system reliability Energy efficiency – e.g. Edison SmartConnectTM advanced metering system

Edison Mission Group

Optimize business financial performance Investments diversify portfolio and emphasize: Renewables led by significant wind development pipeline of ~3,000 MW Gas-fired generation

Advanced fossil fuel technologies

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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, project debt

Focus on organic growth

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 SCE and Edison Capital cash flows fund dividend given EMG growth opportunities

1 Senior unsecured credit ratings shown.

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Earnings Guidance

Reconciliation of Core Earnings Guidance to Total Earnings Guidance

	2007 Guidance
		reaffirmed as
Core EPS1		of 11/02/07
Southern California Edison	$	1.97 - $ 2.07
Edison Mission Group		1.40 - 1.65
EIX parent company and other		(0.13	)
EIX core earnings per share	$	3.24 - $ 3.59
Non-Core Items2
Southern California Edison		0.10
Edison Mission Group		(0.44	)
Total Non-Core Items		(0.34	)
EIX basic earnings per common share	$	2.90 - $ 3.25

1 See use of Non-GAAP Financial Measures in appendix. The impact of participating securities is included in EIX parent company earnings (loss) and is ($0.04).

2 2007 non-core items reflect refinancing costs of $(0.45) and $0.01 per share from discontinued operations for EMG, and a tax benefit of $0.10 per share for SCE.

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Southern California Edison (SCE)

An Investor-Owned Electric Utility

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SCE Value Driver – System Growth

SCE’s service territory has

4 of the 10 fastest growing counties in the nation2

5 of the 25 fastest growing cities in the nation3 New meter connections

Expect to be 75,626 in 2007

385,791 meters added in the past 5 years Home remodeling and population gains in high-temperature regions contribute to growth Peak Demand

August 2007 demand peak 23,303 MW 6.2% growth from 2005 peak 12.2% higher than 2004 peak

Strong customer and load growth keeps statewide focus on the need to expand and strengthen the utility infrastructure

1 2007 figures projected for full-year.

2 LA, Riverside, San Bernardino and Orange counties. US Census Bureau data, in terms of population increase between 2000 and 2005.

3 Moreno Valley, Rancho Cucamonga, Irvine, Lancaster and Fontana. US Census Bureau data, in terms of population percentage increase between 2004 and 2005.

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SCE Value Driver – Renewable Power Procurement

State law requires SCE to increase its procurement of renewables by at least 1% of its annual retail sales per year, so that 20% of such sales are procured from renewables by the end of 20101 SCE’s current renewable portfolio (2006 data)

Renewable resources ~13 billion kWh

Represents ~17% of customer power deliveries SCE’s 2010 renewable resources target ~16 billion kWh Completed four renewable power solicitations to date; 2007 solicitation to be finalized by 2Q 08

SCE – the nation’s leading renewable energy purchaser in 2006

Agreement with Alta Windpower Development LLC

Secures at least 1,500 MW of power, more than doubling SCE’s wind portfolio

The wind project, when completed, will be twice the size of the largest wind project in the U.S.

Projects to be built in Tehachapi, California

Expanded Geothermal Agreement with Calpine

SCE expanded agreement to purchase 225 MW of geothermal energy for 10 years

SCE entered into a new agreement for 714 MW of non-renewable capacity for 2008 – 2011

1 CPUC allows for “cumulative deficit banking” which would enable SCE to carry forward and accumulate annual deficits until the deficit has been satisfied at a later time through actual deliveries of eligible renewable energy.

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SCE Value Driver – Conventional Power Procurement

All-Source RFO

Contracts totaling up to 3,450 MW were executed in January 2007

Contracts cover 2007 – 2011 and include energy and capacity

New all-source RFO was launched in July 2007 and closed in October 2007

Contracts totaling up to 3,250 MW executed covering 2009 – 2013

New Generation RFO

Solicited up to 1,500 MW of new IPP generation – 1,205 MW has been awarded

Summer 2007 Track

NRG received a 10-year PPA to provide 260 MW Project in-service in August 2007

Fast Track

On-line by August 2010

Blythe Energy and Competitive Power Ventures each received 10-year PPAs for 490 and 455 MW, respectively CPUC decision pending

Standard Track

On-line by August 2013 Shortlist notification June 2007

Notification of successful offers in January 2008

In December 2007 the CPUC is expected to determine if additional procurement may be necessary in its upcoming Long-Term Procurement Plan decision

CPUC has provided cost recovery assurance

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SCE Growth Driver – Investment

Proposed Five-Year Capital Spending Plan $ Billions $5 $4 $3 $2 $1 $0

2007 2008 2009 2010 2011 $2.4 $2.8 $3.9 $4.2 $4.0

Forecast by Classification

	$		%
Edison SmartConnectTM		1.3	8
Generation		2.8	16
Transmission		4.3	25
Distribution		8.9	51
Total1		17.3	100
Current Forecast by Proceeding
	$		%
CPUC Rate Cases		11.0	64
CPUC Project Specific		2.0	11
FERC Rate Cases		4.3	25
Total1		17.3	100

Five-year spending plan emphasizes infrastructure replacement, renewables transmission, demand growth and energy efficiency (e.g. Edison SmartConnectTM)

1 Subject to timely receipt of permitting, licensing and regulatory approvals. Forecast is as of March 2007 and includes about $600 million of capital spending for DPV2, the majority of which was expected to occur in 2008 & 2009. The Arizona Corporation Commission (ACC) denied approval of the DPV2 project. SCE filed an appeal and is evaluating its options for the project. The denial will result in a delay of the project.

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SCE Growth Driver – Investment

Forecast SCE Rate Base 2006-20111 $ Billions $21 $18 $15 $12 $9 $6 $3 $0

2006 2007 2008 2009 2010 2011

Approved

Future Regulatory Proceedings

1 2

+

%

Compound

Annual

Growth

R a te $10.9 $11.7 $12.7 $14.5 $17.6 $20.4

Rate base growth provides foundation for strong SCE earnings and cash flow growth while meeting customer service and infrastructure objectives

1 Includes impact of 2006 CPUC and 2006 FERC GRC decisions and forecasted rate base for FERC (2007-2011) and CPUC (2009-2011) which are subject to timely receipt of permitting, licensing and regulatory approvals. Forecast is as of March 2007 and includes about $600 million of capital spending for DPV2, the majority of which was expected to occur in 2008 & 2009. The Arizona Corporation Commission (ACC) denied approval of the DPV2 project. SCE filed an appeal and is evaluating its options for the project. The denial will result in a delay of the project.

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SCE Value Driver – Capital Investment

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

Las Vegas

Midway

Tehachapi SCE Eldorado

(PG&E) Service

Windhub

Territory

Antelope

Palmdale Lugo

Vincent Mohave ARIZONA

Santa Clarita Rancho Pardee Vista

Mira Devers Loma

Serrano Palm Phoenix

Los Angeles Springs

Valley

Santa

Ana Palo Verde

San Diego

			2007-2011
Project Name	Phase	In-Service	($	Millions	) 1
Renewables
Tehachapi Segments 1—3	Licensing2	2008 - 2009		255
Tehachapi Segments 4—11	Licensing	2011 - 2013		1,504
Other Renewable Projects	Licensing	Various		343
Total Renewables				2,102
Reliability
Rancho Vista Substation	Construction	2009		213
Other Reliability Projects	Various	Various		1,351
Total Reliability				1,564
Economics
DPV2	Licensing3	2009		587
GRAND TOTAL				4,253

Existing 500kV Tehachapi Segments 1-3 500kV DPV2 & Rancho Vista 500kV Tehachapi Segments 4-11 500kV

SCE leadership in new transmission to support system reliability and renewable energy

Subject to timely receipt of permitting, licensing and regulatory approvals. Forecast is as of March 2007. CAISO, CPUC approvals received; USFS approval for Segment 1 pending.

CAISO, CPUC, USFWS and Arizona Siting Commission approvals received. The Arizona Corporation Commission (ACC) denied approval of the DPV2 project. SCE filed an appeal and is evaluating its options for the project. The denial will result in a delay of the project.

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SCE Value Driver – Capital Investment

Five “Black Start” Peakers

Initiated in August 2006 at the CPUC’s request Capital investment forecast at approx. $300 million – $279 million spent or firmly committed through September 30, 2007 Four of five units placed on-line in August Oxnard peaker permit denied by the City; SCE is appealing to Coastal Commission and expects a decision in 1Q 08

San Onofre Nuclear Generation Station

• 2,150 MW total (SCE share 78.21%)

• Unit 2 SGR in service 2010

• Unit 3 SGR in service 2011

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SCE Value Driver – Edison SmartConnectTM

2005 2006 2007 2008 2009 2010 2011 2012

Current Schedule1

Design Phase

Pre-Deployment Phase

Deployment Phase

Schedule

Pre-deployment, which began in January 2007, includes field testing with about 3,000 homes under the $45 million Phase II CPUC authorization granted in July 2007 Phase III application filed July 2007 to deploy to 5.3 million residential and small commercial customers between 2008 – 2012; total cost estimate $1.7 billion, of which $1.3 billion is capital cost to be included in rate base1 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

Vendor Candidates

eMeter to provide the meter data management system to support customer billing, energy information and utility operations Corix Utilities selected to provide meter installation services IBM will serve as the system integrator for Edison SmartConnectTM, managing the development and integration for the network management and meter data management system Communications Candidates: Cellnet, Itron Meter 1 Candidates: Itron, Landis + Gyr Meter 2 procurement in progress

SCE leadership in advanced metering infrastructure

1 Subject to CPUC approval.

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SCE Value Driver – Energy Efficiency

Our Goal

Continue to strengthen our commitment to creating and improving energy efficiency (EE) in an environmentally responsible manner by supporting the strong regulatory framework in California where energy efficiency programs can thrive, and creating joint alliances with utilities and other select organizations

Our Past Accomplishments

During the past 5 years, SCE has led the nation in energy-efficiency savings

More than 4B in kWh savings – enough energy to power 500K homes for an entire year

Reduction in greenhouse gas emissions by > 2M tons – the equivalent of taking 250K cars off the road

SCE has been nationally recognized by the U.S. EPA six times

SCE has consistently offered a wide array of energy efficiency and demand response programs, providing financial incentives and/or other benefits for saving energy and shifting usage from on-peak periods

Our Current Achievements

SCE, along with 7 other utilities, recently announced their commitment to invest in energy efficiency and to seek regulatory actions to –

Increase total investment by $500M to $1.5B annually1

Reduce carbon dioxide emissions by an estimated 30M tons by 2016, the equivalent of removing 6M cars from the road, and avoiding the need for fifty 500-MW peaking power plants

Create a national institute within EEI to develop regulatory models and to foster support in the power sector

Recent Developments

? On September 20, the CPUC adopted an Energy Efficiency Risk/Reward Incentive Mechanism for two three-year periods: 2006 – 2008 & 2009 – 2011 (CPUC Decision No. D.0709043)

1 Represents cumulative investment of all eight utilities.

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SCE Energy Efficiency Program Incentives

Under the final decision, SCE would be eligible to receive incentives based on meeting certain targets for savings, measured in terms of kilowatt hours and kilowatts The CPUC set a cumulative three-year energy efficiency savings goal for each utility for the 2006–2008 program cycle. SCE expects to achieve the following stated CPUC targets for its customers in the three-year period:

3.1 billion kilowatt-hours of energy savings; 687 megawatts of demand reduction

More than $2 billion in gross benefits and nearly $1.2 billion in net benefits, after costs Incentives are provided in a range of 9% of net customer benefits for achieving between 85% and 100% of energy efficiency targets and 12% for achieving 100% or more of the targets. Should SCE fall below 65 percent of the CPUC goals, shareholders would incur penalties Both incentives and penalties are capped at $200 million for the three-year period If SCE achieves its energy efficiency and net benefit goals of approximately $1.2 billion, the three-year pre-tax earnings opportunity would be approximately $146 million

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Constructive Regulatory Environment

Rate Base

General Rate Case (GRC) provides three-year forward looking rate-setting mechanism based on forecast spending; affirmed

twice

2006 GRC Decision approved majority of capital requests and operating expenses 2006 GRC Decision results in increased depreciation providing annual cash flow of about $1 billion for 2006–2008 Tendered 2009 GRC Notice of Intent in July 2007 with final application to be filed in November 2007

Investors’ Return

11.6% return on common equity (ROCE) approved through 2007 11.8% ROCE requested May 2007 in 2008 Cost of Capital application to be effective January 2008 (subject to CPUC review and approval)

Energy Efficiency

CPUC adopted mechanism allows for incentives and penalties capped at $200 million for two three-year periods: 2006–2008 & 2009–2011

Procurement Cost

Energy Resources Recovery Account (ERRA) and related Trigger Mechanism provides timely recovery of procurement costs and mitigates energy price exposure

Customer Rates

Increases in base rates (i.e. GRC) expected as the result of rate base growth. Total customer rates, however, not expected to increase appreciably due to reduction in natural gas prices

California’s regulatory framework has been strengthened to support growth and reliability needs, and mitigate risks of volatile commodity prices

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Edison Mission Group (EMG)

A Competitive Power Generation Company

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EMG – Business and Wind Growth Platforms

Washington Natural Gas 70 MW

California

Natural Gas 964 MW

Nebraska

Wind (Pipeline) 80 MW

Wyoming

Wind (UC) 141 MW

Utah

Wind (Pipeline) 89 MW

Oklahoma

Wind (UC) 95 MW Wind (Pipeline) 300 MW

Nevada

Wind (Pipeline) 315 MW

New Mexico

Wind 90 MW

Wind (Pipeline) 160 MW

Texas

Wind 161 MW Wind (UC) 150 MW Wind (Pipeline) 480 MW

Iowa

Wind 145 MW

Wind (Pipeline) 200 MW

Minnesota

Wind 75 MW Wind (UC) 70 MW Wind (Pipeline) 169 MW

Illinois

Coal 5,613 MW Natural Gas 305 MW Wind (Pipeline) 420 MW

Pennsylvania

Coal 1,884 MW Wind (UC) 67 MW Wind (Pipeline) 60 MW

Wisconsin

Wind (Pipeline) 100 MW

Maine

Wind (Pipeline) 54 MW

New York

Wind (Pipeline) 130 MW

Maryland

Wind (Pipeline) 80 MW

West Virginia

Coal 40 MW

Wind (Pipeline) 345 MW

Operating Platform1
	MW	%
Coal	7,537	79	%
Natural Gas	1,339	14	%
Wind	471	5	%
Other	153	2	%
	9,500	100	%

Wind Development Pipeline1
	MW
Under Construction	523
Pipeline2	2,982
Turbines (Not Shown) 1,185

1 Natural gas includes oil-fired; other includes Doga in Turkey (144 MW) and Huntington biomass (9 MW) which are not shown. Turbines purchased or committed to support development pipeline. Data as of September 30, 2007.

2 Data as of September 30, 2007; owned or under exclusive agreement.

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EMG – Key Value Drivers

Low-cost coal generation driver for strong EBITDA

EMG adjusted EBITDA in excess of $1 billion for last two years, also forecasted for 20071 Strong operational and marketing/trading capabilities

Effective management of fuel, transportation, and emissions to protect gross margin

More efficient and expanding market/hedging opportunities

Experienced/value-adding trading business

Long-term environmental plan for Midwest Generation Financial flexibility

EMG liquidity2 – approximately $2.5 billion as of September 30, 2007

Recent financing eliminates near-term maturities and high interest rate notes Expansion and diversification goals

Larger scale and operational efficiencies

Greater diversification of generation technology and fuel type

Bias towards development, contract vs. merchant, low emission-technologies

Focus areas – renewables, natural gas, IGCC

1 See Edison Mission Group adjusted EBITDA in appendix for reconciliation to net income; 2007 adjusted EBITDA calculation based on mid-point of EMG guidance range.

2 See EMG liquidity profile.

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Midwest Generation – Operating Performance

YTD 07 vs. YTD 06

Generation up about 9.5%

Capacity and Load Factors increased on higher off-peak sales

Forced Outage Rate was higher due to unplanned boiler tube leaks and coal-related equipment failures

	YTD		YTD
Operating Statistics	07		06
Total Generation (GWh)	23,169		21,167
Equivalent Availability	78.7	%	80.9	%
Capacity Factor	63.0	%	57.6	%
Load Factor	80.1	%	71.2	%
Forced Outage Rate	7.0	%	5.7	%

All-in average realized price increased by about 9.9% per MWh YTD compared to the same period last year

All-in Average Realized Prices1 $60

$40

$/MWh $20

$0 $54.17 $53.30 $51.03 $48.52 $40.29 $39.90 $36.91 $34.99 $13.88 $14.12 $13.40 $13.53

3Q 07 3Q 06 YTD 07 YTD 06

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

1 Includes the price of energy, capacity, ancillary services, etc.

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

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Homer City – Operating Performance

YTD 07 vs. YTD 06

Generation up about 12.8%

2006 Availability and Forced Outage Rates impacted by the Unit 3 transformer failure

	YTD		YTD
Operating Statistics	07		06
Total Generation (GWh)	10,211		9,052
Equivalent Availability	89.0	%	79.4	%
Capacity Factor	82.6	%	73.2	%
Load Factor	92.8	%	92.1	%
Forced Outage Rate	3.7	%	16.9	%

All-in average realized price increased by over 14.3% per MWh YTD compared to the same period last year

All-in average Realized Prices1 $60

$40

$/MWh $20

$0 $53.60 $56.48 $49.19 $49.40 $31.12 $34.48 $26.27 $25.82 $22.48 $22.92 $22.00 $23.58

3Q 07 3Q 06 YTD 07 YTD 06

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

1 Includes the price of energy, capacity, ancillary services, etc.

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

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EMG Hedge Program Status

Status at September 30, 2007		Remainder
		of
		2007		2008		2009		2010
Midwest Generation
Energy Only Contracts
Megawatt hours (in GWh)		4,132		10,838		7,487		3,472
Average Price ($/MWh)	$	48.18	$	61.36	$	62.28	$	62.62
Load Requirement Services Contracts
Estimated GWh1		1,862		5,613		1,632		–
Average price ($/MWh) 2	$	63.63	$	64.01	$	63.65		–
Total estimated GWh hedged		5,994		16,451		9,119		3,472
Coal under contract (in millions of tons)		5.0		14.6		11.7		11.7
Homer City
Total estimated GWh hedged		1,912		7,232		3,890		1,022
Average price ($ /MWh)	$	64.29	$	60.87	$	74.88	$	77.80
Coal under contract (in millions of tons)		1.4		4.4		3.5		0.2

1 The amount of power sold is a portion of the retail load of the purchasing utility and can vary significantly with variations in that retail load. Retail load depends upon a number of factors, including the time of day and year, and the utility’s number of new and continuing customers. Estimated MWh have been forecast based on historical patterns and on assumptions regarding the factors that may affect retail loads in the future. 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, which is 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. Also, Midwest Generation will incur charges from PJM as a load-serving entity. Thus, 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.

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EMG Capacity Sales

Status at September 30, 2007		October 1, 2007 - May 31, 2008						June 1, 2008 - May 31, 2009						June 1, 2009 - May 31, 2010
		Midwest			Homer			Midwest			Homer			Midwest			Homer
Megawatts except price per MW-day		Generation			City			Generation			City			Generation			City 3
INSTALLED CAPACITY		5,918			1,884			5,918			1,884			5,918			1,884
Less: Net capacity held due to loadrequirements servicescontracts,1 and retained for		(2,822	)		(213	)		(1,755	)		(173	)		(589	)		(214	)
outages
NET CAPACITY AVAILABLE FOR SALE		3,096			1,671			4,163			1,711			5,329			1,670
Fixed Price Capacity Sales
· RPM Auction Process
- Net Capacity Sold		2,596			786			3,283			820			4,614			1,670
- Price per MW-day	$	40.80		$	40.80		$	111.92		$	111.92		$	102.04		$	191.32
· Non-unit Specific Capacity Sales
- Net Capacity Sold		500			—			880			—			715			—
- Price per MW-day (Net)	$	21.31		$	—		$	64.35			—		$	71.46			—
Variable Capacity Sales
· Third Party Transaction
- Capacity		—			885			—			891			—			—
- Expected price per MW-day 2	$	—		$	66.72		$	—		$	72.11			—			—
TOTAL CAPACITY SOLD		3,096			1,671			4,163			1,711			5,329			1,670
AVERAGE PRICE PER MW-DAY	$	37.65		$	54.53		$	101.86		$	91.19		$	97.94		$	191.32

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

2 Actual contract price for Homer City sale is a function of NYISO capacity auction clearing prices. Capacity price per MW-day is based on forward over-the-counter NYISO prices on September 28, 2007.

3 Homer City was segregated out of the “rest of market” location in PJM into MAAC + APS.

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EMG – Operational, Marketing and Trading Capabilities

Optimize forward sales opportunities

Extending hedge program Reducing collateral requirements

RPM Auctions provide new option to sell capacity

June 1, 2009 – May 31, 2010 auction

• Clearing price for MWG = $102.04/MW-day

• Homer City clearing price = $191.32/MW-day

• Sold net 4,614 MW of capacity from MWG and net 1,670 MW of capacity from Homer

City

EMMT provides opportunistic trading revenues

Leverage knowledge gained from managing merchant coal fleet

Trading primarily transmission congestion products and electricity basis spreads

Controls on types and sizes of exposures

Allowed products and region (large majority of positions are low-risk congestion contracts)

VaR, volumetric, duration and credit limits

EMMT Trading Revenue

($ MM pre-tax)

200 150 100 50 0 $23 $195 $130 $103

2004 2005 2006 2007 YTD

Edison Mission Marketing and Trading provides significant incremental income from trading activity

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EMG Growth Driver – Recapitalization $2.7 billion EMG refinancing Favorable market conditions Enhanced financial flexibility

Moves refinancing risk past environmental spending period Simplifies capital structure Facilitates longer-term hedging Expands liquidity

Tender premium and other non-core1 costs: $0.45 per share

2007 Edison Mission Energy Debt Financing $1.200 billion 7.00% Senior Notes due 2017 . $800 million 7.20% Senior Notes due 2019 . $700 million 7.625% Senior Notes due 2027 .

1 See Year-to-Date Financial Results in appendix for reconciliation of core earnings to reported earnings.

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EMG – Midwest Gen Environmental Agreement

Comprehensive agreement addresses mercury, NOx, and SO2 emissions

Achieves specified emission reductions through retrofits or unit shutdowns

Mercury – 90% removal by 2015

NOx – emissions of 0.11 lbs. per million Btus by 2011 (66% reduction)

SO2 – emissions of 0.11 lbs. per million Btus by 2019, with interim step downs

(78% reduction)

Helps continue good relationships with key constituents and regulators and supports growth

Agreement supported by Gov. Blagojevich, City of Chicago, and several influential environmental and community groups

Illinois EPA assistance with IGCC and wind development, permit approvals Emission credit selling allowed Agreement filed under Illinois State Implementation Plan of CAIR

Provides reasonable certainty of amount & timing of emission reductions through 2018

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EMG – Environmental Compliance

MWG Compliance Plan

Phase 1 – Reduction of Mercury Emissions

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

Estimated cost approx. $60 million

Phase 2 – Reduction of NOx Emissions

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

Estimated cost approx. $450 million

Phase 3 – Reduction of SO2 Emissions

Flue Gas Desulfurization (FGD) technology

Estimated cost $2.2 – $2.9 billion Shutdown of Small Units

Waukegan 6 (100 MW) – by end of 2007

Will County 1 & 2 (310 MW) – by end of 2010

Homer City Compliance Plan

PA State Implementation Plan for CAMR and CAIR adopted Homer City will comply with 2010 phase of mercury requirements by installing ACI on Units 1 & 2 Evaluating compliance approaches for 2015 phase

EMG environmental compliance plan allows assessment of market conditions before incurring capital expenditures

Note: Cost estimates are in 2006 dollars.

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EMG – 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 Leverages successful wind energy experience to date

Wind energy provides attractive opportunities

Growing RPS requirements and national desire for renewables Production tax credits Accelerated depreciation (MACRS) over 5 yrs. Mainly long-term contracts for output

Wind Project Portfolio & Development Pipeline

Projects1	No. of Projects	MW
In-Service	12	471
Under Construction	8	523
Total Projects	20	994
Development Pipeline2	28	2,982
Turbines
Purchased and under option		1,185

Pipeline of about 3,000 MWs under exclusive development agreements Extensive prospect list supports further growth of development pipeline Purchased and option for 1,185 MW of turbines for 2007—2010 delivery

1 Data as of September 30, 2007; turbines purchased or committed to support development pipeline

2 Owned or under exclusive agreements.

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EMG – Thermal Growth Project Opportunities

Natural Gas-Fired Generation

Thermal development (1,000 MW)

Walnut Creek and Sun Valley, CA opportunities (500 MW each) in permitting and engineering stage – SCE and other potential customers Potential acquisitions of assets or portfolios

Will be selective and disciplined

Some regions showing developing capacity markets and higher spark spreads

Assets complement marketing and trading skills

Advanced Fossil-Fuel Technologies

Carson Hydrogen Project (400-450 MW)

Joint Venture with BP at their Carson City refinery –

petroleum coke fuel with 90% CO2 used for enhanced

oil recovery (EOR)

Confirming project economics and CO2 requirements

Other opportunities in early stage development

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Appendix

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What’s New Since Our Last Update

New Information

SCE Energy Efficiency incentive mechanism (see pages 18 – 19)

Updated Information

SCE New All-Source RFO generation timeline (see page 12) Peaker update (see page 16) Edison SmartConnectTM (see page 17) EMG operating, hedging and trading updates (see pages 24 – 28) EMG wind development (see page 32)

Third Quarter and YTD 2007 earnings and financial update (see pages 36 – 37)

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Third Quarter Financial Results

Reconciliation of Core Earnings to Reported Earnings

Core Earnings		3Q 07			3Q 06			Var.
SCE	$	0.80		$	0.74		$	0.06
EMG		0.64			0.62			0.02
EIX Holding Co.		(0.03	)		(0.04	)		0.01
Core EPS1	$	1.41		$	1.32		$	0.09
Non-Core Items
SCE	$	–		$	0.07		$	(0.07	)
EMG		(0.01	)		(0.01	)		–
Total Non-Core		(0.01	)		0.06			(0.07	)
Basic EPS	$	1.40		$	1.38		$	0.02
Diluted EPS	$	1.39		$	1.38		$	0.01

Core Earnings Variances
SCE
Primarily due to higher net revenue associated with the 2006	0.06
GRC decision
EMG
Midwest Generation
Primarily due to lower interest expense from debt repayment	0.09
in 2Q 07 and higher realized energy margin, partially offsetby SFAS #133 impact
Homer City
No change in income 3Q 07 vs. 3Q 06 mainly due to higher	–
realized energy margin offset by SFAS #133 impact
Income from Other Projects
Primarily from higher income from wind projects	0.03
Corporate Expense and Other Items
Primarily higher development costs and other corporate	-0.07
expenses
Edison Capital
Lower results from leases and infrastructure fund investments	-0.03
Non-Core Variances
SCE Benefit related to generator settlement	-0.07
EMG Discontinued operations	–

1 See use of Non-GAAP Financial Measures in appendix. The impact of participating securities is included in EIX parent company earnings (loss) and was $(0.02) and $(0.03) per share for the quarter ended September 30, 2007 and 2006, respectively.

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Year-to-Date Financial Results

Reconciliation of Core Earnings to Reported Earnings
Core Earnings		YTD 07			YTD 06			Var.
SCE	$	1.70		$	1.58		$	0.12
EMG		1.41			0.95			0.46
EIX Holding Co.		(0.07	)		(0.10	)		0.03
Core EPS1	$	3.04		$	2.43		$	0.61
Non-Core Items
SCE	$	0.10		$	0.32		$	(0.22	)
EMG		(0.45	)		(0.04	)		(0.41	)
Total Non-Core		(0.35	)		0.28			(0.63	)
Basic EPS	$	2.69		$	2.71		$	(0.02	)
Diluted EPS	$	2.67		$	2.71		$	(0.04	)

Core Earnings Variances
SCE
Primarily due to higher net revenue associated with the 2006 GRC decision		0.12
and lower income taxes
EMG
Midwest Generation
Mainly higher realized energy margin (driven by higher generation and		0.34
higher average realized prices) partially offset by SFAS #133 impact,and lower interest expense
Homer City
Primarily higher realized energy margin (driven by higher generation and		0.12
higher average realized energy prices), which includes higher capacityrevenue resulting from the PJM RPM auction, partially offset by SFAS
#133 impact
Income from Other Projects
Higher income from wind and gas-fired projects		0.08
Edison Capital
Gains on global infrastructure fund investments and higher interest income
		0.04
Corporate Expense and Other Items
Higher development costs and other corporate expenses and higher net		-0.12
interest/other expense (Mirant income and gain on sale of 25% interest in
San Juan Mesa recorded in 06)
Non-Core Variances
SCE YTD 07: $ 0.10 reflects progress made with the IRS related to the		-0.22
income tax treatment of certain environmental remediation costs; YTD 06:
$ 0.25 relates to the resolution of an outstanding issue involving a portion ofrevenue collected during 2001—2003 related to state income taxes and	$	0.07
reflects generator settlement.
EMG YTD 07 and YTD 06 include ($ 0.45) and ($0.27) per share for early		-0.41
debt extinguishment charges; $0.01 and $0.26 per share from proceeds fromdiscontinued operations related to Lakeland; and ( $0.01) and ($0.03) per sharefrom other discontinued operations, respectively.

1 See use of Non-GAAP Financial Measures in appendix. The impact of participating securities is included in EIX parent company earnings (loss) and was $(0.03) per share for year-to-date September 30, 2007 and 2006.

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EMG—2005-2007E Adjusted EBIDTA

	2005			2006			2007
Reconciliation to Net Income ($ Millions)		Actual			Actual			Forecast
Net Income	$	443		$	432		$	3541
Add back (Deduct):
Cumulative effect of change in accounting,		1			(1	)		?
net of tax
Discontinued operations		(30	)		(97	)		(5	)
Income (loss) from continuing operations		414			334			349
Interest expense		435			409			329
Interest income		(74	)		(118	)		(82	)
Income taxes		163			154			127
Depreciation and amortization		147			157			175
EBITDA		1,085			936			898
Production tax credits2		8			17			30
Discrete items:
Loss on lease, asset impairment and other		7			?			?
Impairment of equity method investment		55			?			?
Gain on sale of assets		?			(22	)		?
Loss on early extinguishment of debt		25			146			241
Adjusted EBITDA	$	1,180		$	1,077		$	1,169

Note: 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.

1 Represents the mid-point of the EMG guidance range.

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

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EMG – Liquidity Profile

Available Liquidity

Sources ($ Millions)		12/31/06		9/30/07
EME Revolver	$	473	$	508
MWG Revolver		495		497
Cash & Short term investments1		2,181		1,517
Total	$	3,149	$	2,522

$1.1 billion of credit facilities between MWG and EME

1 Excludes $73 million and $109 million of cash collateral held by counterparties at 12/31/06 and 9/30/07, respectively.

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EMG – Capital Expenditures

Planned Expenditures1

October 2007 – 2009

Plant/Corporate Capex Plan Environmental Plan Growth Commitments $ Millions

900 450 0

2007 2008 2009

Total $1,904 Million

1 EME expects to make substantial investments in new projects during the next three years. As of September 30, 2007, EME had a development pipeline of potential wind projects with an estimated installed capacity of approximately 3,000 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 which may include, depending on the project’s status, completion of a power sales agreement, permits, an interconnection agreement or other agreements necessary to start construction. Additional projects may from time to time be added to the development pipeline, 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.

Potential Expenditures (2007 – 2009)

Additional growth opportunities Additional wind turbines

Balance of plant costs for purchased wind turbines

Potential Expenditures After 2009

Midwest Generation environmental spending plan Evaluating FGD installation at Homer City Additional growth opportunities

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SCE – Regulatory Update

Edison SmartConnectTM

GRC

Cost of Capital

Tehachapi Transmission

DPV 2 –Transmission

FERC Transmission Incentives Filing

Case	Date of		Next
Number	Filing	Status	Milestone
Phase III A. 07-07-026	July 31, 2007	Phases I and II approved Phase III request is for $1.3 B capital ($1.7 B total) over 2008- 2012 time period	Evidentiary hearings February, 2008. Final Phase III decision expected July 2008
None until application is filed	July 23, 2007	CPUC Staff accepted NOI	GRC Application expected to be filed on November 19, 2007
A. 07-05-003	May 8, 2007	SCE proposed 11.8% ROCE with a 48% common equity capital structure	Proposed decision expected November 6, 2007
I. 05-09-005 D. 04-06-010	November, 2000	Segments 1-3 are approved (except for USFS exp. 4Q 07), Segments 4-11 application filed June 2007	Proposed pre-hearing conference March 2008
ACC: L-00000A- 029500130	April, 2005 (with CPUC)	ACC has denied approval of application (May). SCE filed an appeal in August.	Evaluating options for the project
EL07-62-000	May 18, 2007	In FERC approval process	Decision expected by year-end 2007

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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.

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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