EIX 10-Q Quarterly Report June 30, 2010

EDISON INTERNATIONAL

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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


(Mark One)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended June 30, 2010
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to
Commission File Number 1-9936

EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)


California		95-4137452
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
2244 Walnut Grove Avenue (P. O. Box 976) Rosemead, California		91770
(Address of principal executive offices)		(Zip Code)
(626) 302-2222 (Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.


Large accelerated filer ý		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

Class		Outstanding at August 2, 2010

Common Stock, no par value		325,811,206

Table of Contents

TABLE OF CONTENTS


GLOSSARY				i
PART I. FINANCIAL INFORMATION				1
ITEM 1. FINANCIAL STATEMENTS				1
	Consolidated Statements of Income (Loss)			1
	Consolidated Statements of Comprehensive Income (Loss)			2
	Consolidated Balance Sheets			3
	Consolidated Statements of Cash Flows			5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS			7
	Note 1. Summary of Significant Accounting Policies			7
	Note 2. Derivative Instruments and Hedging Activities			10
	Note 3. Liabilities and Lines of Credit			17
	Note 4. Income Taxes			18
	Note 5. Compensation and Benefit Plans			20
	Note 6. Commitments and Contingencies			22
	Note 7. Consolidated Statements of Changes in Equity			35
	Note 8. Accumulated Other Comprehensive Income			36
	Note 9. Supplemental Cash Flows Information			36
	Note 10. Fair Value Measurements			37
	Note 11. Regulatory Assets and Liabilities			43
	Note 12. Other Income and Expenses			44
	Note 13. Variable Interest Entities			44
	Note 14. Business Segments			48
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				50
	FORWARD-LOOKING STATEMENTS			50
EDISON INTERNATIONAL OVERVIEW
	Introduction			52
	Highlights of Operating Results			52
	SCE Capital Program			54
	SCE 2012 General Rate Case			54
	Environmental Developments			55
		Midwest Generation Environmental Compliance Plans and Costs		55
		Environmental Regulation Developments		55
			Greenhouse Gas Regulation Developments	55
			Transport Rule and Coal Combustion Waste Regulation	56
			California Renewable Energy Developments	56
			Once-Through Cooling	56

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	EMG Renewable Program				56
		Mitsubishi Lawsuit			57
	Parent Company Liquidity				57
SOUTHERN CALIFORNIA EDISON COMPANY
	RESULTS OF OPERATIONS				58
	Electric Utility Results of Operations				58
		Three Months Ended June 30, 2010 versus June 30, 2009			59
			Utility Earning Activities		60
			Utility Cost-Recovery Activities		60
		Six Months Ended June 30, 2010 versus June 30, 2009			61
			Utility Earning Activities		61
			Utility Cost-Recovery Activities		63
		Supplemental Operating Revenue Information			63
		Income Taxes			64
	LIQUIDITY AND CAPITAL RESOURCES				64
	Available Liquidity				64
		Debt Covenant			65
	Regulatory Proceedings				65
		Energy Efficiency Risk/Reward Incentive Mechanism			65
		2010 FERC Rate Case			65
	Dividend Restrictions				65
	Margin and Collateral Deposits				65
	Historical Consolidated Cash Flow				66
		Condensed Consolidated Statement of Cash Flows			66
			Cash Flows Provided by Operating Activities		66
			Cash Flows Provided (Used) by Financing Activities		66
			Cash Flows Used by Investing Activities		67
	Contractual Obligations and Contingencies				67
		Contractual Obligations			67
		Contingencies			67
			Environmental Remediation		67
	MARKET RISK EXPOSURES				67
	Interest Rate Risk				67
	Commodity Price Risk				68
		Natural Gas and Electricity Price Risk			68
	Credit Risk				69
EDISON MISSION GROUP
	RESULTS OF OPERATIONS				70
	Results of Continuing Operations				70
		Adjusted Operating Income ("AOI") – Overview			71
		Adjusted Operating Income from Consolidated Operations			73
			Midwest Generation Plants		73
			Homer City Facilities		74
			Non-GAAP Disclosures—Fossil-Fueled Facilities		75
				Adjusted Operating Income	75

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		Seasonal Disclosure—Fossil-Fueled Facilities	75
		Renewable Energy Projects	76
		Energy Trading	77
	Adjusted Operating Income from Leveraged Lease Activities		77
	Adjusted Operating Income from Lease Termination and Other		77
	Adjusted Operating Income from Unconsolidated Affiliates		77
		Doga	77
		March Point	77
		Seasonal Disclosure	77
	Interest Related Income (Expense)		78
	Income Taxes		78
Results of Discontinued Operations			78
Derivative Instruments			79
	Unrealized Gains and Losses		79
	Fair Value Disclosures		79
LIQUIDITY AND CAPITAL RESOURCES			79
Available Liquidity			79
Capital Investment Plan			81
	Estimated Expenditures for Existing Projects		81
	Estimated Expenditures for Future Projects		82
Historical Consolidated Cash Flow			82
	Condensed Consolidated Statement of Cash Flows		82
		Cash Flows Used by Operating Activities	82
		Cash Flows Provided (Used) by Financing Activities	83
		Cash Flows Provided (Used) by Investing Activities	83
Credit Ratings			83
	Overview		83
	Credit Rating of EMMT		83
	Margin, Collateral Deposits and Other Credit Support for Energy Contracts		83
Debt Covenants and Dividend Restrictions			84
	Credit Facility and Financial Ratios		84
	Dividend Restrictions in Major Financings		85
	EME's Senior Notes and Guaranty of Powerton-Joliet Leases		85
Contractual Obligations and Contingencies			85
	Fuel Supply and Transportation Contracts		85
	Midwest Generation New Source Review Lawsuit		85
	Homer City New Source Review Notice of Violation		85
Off-Balance Sheet Transactions			85
Environmental Matters and Regulations			86
MARKET RISK EXPOSURES			86
Commodity Price Risk			86
	Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities		86
	Capacity Price Risk		88
	Basis Risk		88
	Coal and Transportation Price Risk		89
	Emission Allowances Price Risk		89

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	Credit Risk			90
	Interest Rate Risk			91
EDISON INTERNATIONAL PARENT AND OTHER
	RESULTS OF OPERATIONS			92
	LIQUIDITY AND CAPITAL RESOURCES			92
	Historical Cash Flow			92
		Condensed Statement of Cash Flows		92
			Cash Flows Provided (Used) by Financing Activities	92
EDISON INTERNATIONAL (CONSOLIDATED)
	CONTRACTUAL OBLIGATIONS			93
	NEW ACCOUNTING GUIDANCE			93
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				93
ITEM 4. CONTROLS AND PROCEDURES				93
	Disclosure Controls and Procedures			93
	Changes in Internal Control Over Financial Reporting			93
PART II. OTHER INFORMATION				94
ITEM 1. LEGAL PROCEEDINGS				94
	Homer City New Source Review Notice of Violation			94
	Midwest Generation New Source Review Lawsuit			94
	Mitsubishi Lawsuit			94
	Navajo Nation Litigation			95
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS				95
ITEM 6. EXHIBITS				96
SIGNATURE				97

Table of Contents

GLOSSARY

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.


2009 Form 10-K		Edison International's Annual Report on Form 10-K for the year ended December 31, 2009
AB		Assembly Bill
AFUDC		allowance for funds used during construction
Ambit project		American Bituminous Power Partners, L.P.
AOI		Adjusted Operating Income
APS		Arizona Public Service Company
ARO(s)		asset retirement obligation(s)
BACT		best available control technology
BART		best available retrofit technology
Bcf		billion cubic feet
Big 4		Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
Btu		British thermal units
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAISO		California Independent System Operator
CAMR		Clean Air Mercury Rule
CARB		California Air Resources Board
Commonwealth Edison		Commonwealth Edison Company
CDWR		California Department of Water Resources
CEC		California Energy Commission
CONE		cost of new entry
CPS		Combined Pollutant Standard
CPUC		California Public Utilities Commission
CRRs		congestion revenue rights
DCR		Devers-Colorado River
DOE		U.S. Department of Energy
DOJ		U.S. Department of Justice
DRA		Division of Ratepayer Advocates
DWP		Los Angeles Department of Water & Power
EME		Edison Mission Energy
EMG		Edison Mission Group Inc.
EMMT		Edison Mission Marketing & Trading, Inc.
EPS		earnings per share
ERRA		energy resource recovery account
EWG		Exempt Wholesale Generator
Exelon Generation		Exelon Generation Company LLC
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGD		flue gas desulfurization
FGIC		Financial Guarantee Insurance Company
FTRs		firm transmission rights
Four Corners		coal fueled electric generating facility located in Farmington, New Mexico in which Edison International holds a 48% ownership interest
GAAP		generally accepted accounting principles

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Global Settlement		A settlement between Edison International and the IRS that resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002.
GRC		General Rate Case
GWh		Gigawatt-hours
Homer City		EME Homer City Generation L.P.
Illinois EPA		Illinois Environmental Protection Agency
Illinois PCB		Illinois Pollution Control Board
Investor-Owned Utilities		SCE, SDG&E and PG&E
IRS		Internal Revenue Service
ISO		Independent System Operator
kWh(s)		kilowatt-hour(s)
LIBOR		London Interbank Offered Rate
MD&A		Management's Discussion and Analysis of Financial Condition and Results of Operations in this report
MEHC		Mission Energy Holding Company
Midwest Generation		Midwest Generation, LLC
Midwest Generation Plants		EME's power plants (fossil fuel) located in Illinois
MMBtu		million British thermal units
Mohave		two coal fueled electric generating facilities that no longer operate located in Clark County, Nevada in which SCE holds a 56% ownership interest
Moody's		Moody's Investors Service
MRTU		Market Redesign and Technology Upgrade
MW		Megawatts
MWh		megawatt-hours
NAAQS		national ambient air quality standards
NAPP		Northern Appalachian
NERC		North American Electric Reliability Corporation
Ninth Circuit		U.S. Court of Appeals for the Ninth Circuit
NOV		notice of violation
NO _x		nitrogen oxide
NRC		Nuclear Regulatory Commission
NSR		New Source Review
PADEP		Pennsylvania Department of Environmental Protection
Palo Verde		large pressurized water nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest
PBOP(s)		Postretirement benefits other than pension(s)
PBR		performance-based ratemaking
PG&E		Pacific Gas & Electric Company
PJM		PJM Interconnection, LLC
POD		Presiding Officer's Decision
PRB		Powder River Basin
PSD		Prevention of Significant Deterioration
PUHCA 2005		Public Utility Holding Company Act of 2005
PX		California Power Exchange
QF(s)		qualifying facility(ies)
RGGI		Regional Greenhouse Gas Initiative
RICO		Racketeer Influenced and Corrupt Organization
ROE		return on equity

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RPM		reliability pricing model
RTO		Regional Transmission Organization
S&P		Standard & Poor's Ratings Services
San Onofre		large pressurized water nuclear electric generating facility located in South San Clemente, California in which SCE holds a 78.21% ownership interest
SB		Senate Bill
SCAQMD		South Coast Air Quality Management District
SCE		Southern California Edison Company
SCR		selective catalytic reduction
SNCR		selective non-catalytic reduction
SDG&E		San Diego Gas & Electric
SEC		U.S. Securities and Exchange Commission
SIP(s)		State Implementation Plan(s)
SO ₂		sulfur dioxide
SRP		Salt River Project Agricultural Improvement and Power District
TURN		The Utility Reform Network
US EPA		U.S. Environmental Protection Agency
VIE(s)		variable interest entity(ies)

iii

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



Consolidated Statements of Income (Loss)	Edison International
	Three Months Ended June 30,						Six Months Ended June 30,

(in millions, except per-share amounts)	2010			2009			2010			2009

	(Unaudited)
Electric utility	$	2,246		$	2,272		$	4,405		$	4,460
Competitive power generation		495			562			1,147			1,186

Total operating revenue		2,741			2,834			5,552			5,646

Fuel		254			328			549			715
Purchased power		612			583			1,220			1,124
Operations and maintenance		1,144			1,074			2,181			2,043
Depreciation, decommissioning and amortization		380			347			749			688
Lease terminations and other		—			866			2			888

Total operating expenses		2,390			3,198			4,701			5,458

Operating income (loss)		351			(364	)		851			188
Interest and dividend income		4			17			23			27
Equity in income (loss) from partnerships and unconsolidated subsidiaries – net		20			6			39			(2	)
Other income		36			30			70			58
Interest expense – net of amounts capitalized		(175	)		(182	)		(343	)		(369	)
Other expenses		(16	)		(17	)		(28	)		(25	)

Income (loss) from continuing operations before income taxes		220			(510	)		612			(123	)
Income tax expense (benefit)		(136	)		(524	)		14			(402	)

Income from continuing operations		356			14			598			279
Income (loss) from discontinued operations – net of tax		1			(7	)		8			(4	)

Net income		357			7			606			275
Less: Net income attributable to noncontrolling interests		13			23			26			41

Net income (loss) attributable to Edison International common shareholders	$	344		$	(16	)	$	580		$	234

Amounts attributable to Edison International common shareholders:
Income (loss) from continuing operations, net of tax	$	343		$	(9	)	$	572		$	238
Income (loss) from discontinued operations, net of tax		1			(7	)		8			(4	)

Net income (loss) attributable to Edison International common shareholders	$	344		$	(16	)	$	580		$	234

Basic earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding		326			326			326			326
Continuing operations	$	1.05		$	(0.03	)	$	1.75		$	0.73
Discontinued operations		—			(0.02	)		0.02			(0.01	)

Total	$	1.05		$	(0.05	)	$	1.77		$	0.72

Diluted earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities		327			327			327			327
Continuing operations	$	1.05		$	(0.03	)	$	1.75		$	0.73
Discontinued operations		—			(0.02	)		0.02			(0.01	)

Total	$	1.05		$	(0.05	)	$	1.77		$	0.72

Dividends declared per common share	$	0.315		$	0.31		$	0.63		$	0.62

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Comprehensive Income (Loss)			Edison International
			Three Months Ended June 30,						Six Months Ended June 30,

(in millions)			2010			2009			2010			2009

			(Unaudited)
Net Income			$	357		$	7		$	606		$	275
Other comprehensive income (loss), net of tax:
	Foreign currency translation adjustments – net			—			4			—			4
	Pension and postretirement benefits other than pensions:
		Net gain arising during the period		—			1			12			1
		Amortization of net (gain) loss included in net income		2			1			(6	)		3
		Prior service adjustment arising during the period		—			—			2			—
		Amortization of prior service adjustment		—			—			(2	)		—
	Unrealized gain (loss) on derivatives qualified as cash flow hedges:
		Unrealized holding gain (loss) arising during the period, net of income tax expense (benefit) of $(50) and $(50) for the three months and $12 and $48 for the six months ended June 30, 2010 and 2009, respectively		(77	)		(90	)		18			61
		Reclassification adjustments included in net income, net of income tax expense (benefit) of $(35) and $9 for the three months and $(49) and $(23) for the six months ended June 30, 2010 and 2009, respectively		(53	)		17			(73	)		(32	)

Other comprehensive income (loss)				(128	)		(67	)		(49	)		37

Comprehensive income (loss)				229			(60	)		557			312
Less: Comprehensive income attributable to noncontrolling interests				13			23			26			41

Comprehensive income (loss) attributable to Edison International			$	216		$	(83	)	$	531		$	271

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Balance Sheets		Edison International
(in millions)		June 30, 2010			December 31, 2009

		(Unaudited)
ASSETS
Cash and equivalents		$	868		$	1,673
Short-term investments			7			10
Receivables, less allowances of $53 for uncollectible accounts at both dates			880			1,017
Accrued unbilled revenue			542			347
Inventory			556			533
Derivative assets			224			357
Restricted cash			25			69
Margin and collateral deposits			111			125
Regulatory assets			338			120
Deferred income taxes			—			3
Other current assets			306			176

Total current assets			3,857			4,430

Competitive power generation and other property – less accumulated depreciation of $1,730 and $2,231 at respective dates			5,112			5,147
Nuclear decommissioning trusts			3,083			3,140
Investments in partnerships and unconsolidated subsidiaries			515			216
Investments in leveraged leases			153			160
Other investments			98			91

Total investments and other assets			8,961			8,754

Utility plant, at original cost:
	Transmission and distribution		23,355			22,214
	Generation		2,715			2,667
Accumulated depreciation			(6,047	)		(5,921	)
Construction work in progress			2,682			2,701
Nuclear fuel, at amortized cost			339			305

Total utility plant			23,044			21,966

Derivative assets			276			268
Restricted deposits			44			43
Rent payments in excess of levelized rent expense under plant operating leases			1,149			1,038
Regulatory assets			5,058			4,139
Other long-term assets			666			806

Total long-term assets			7,193			6,294

Total assets		$	43,055		$	41,444

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Balance Sheets	Edison International
(in millions, except share amounts)	June 30, 2010			December 31, 2009

	(Unaudited)
LIABILITIES AND EQUITY
Short-term debt	$	495		$	85
Current portion of long-term debt		42			377
Accounts payable		1,027			1,347
Accrued taxes		131			186
Accrued interest		210			196
Customer deposits		229			238
Derivative liabilities		179			107
Regulatory liabilities		457			367
Deferred income taxes		114			—
Other current liabilities		729			884

Total current liabilities		3,613			3,787

Long-term debt		11,113			10,437

Deferred income taxes		4,639			4,334
Deferred investment tax credits		98			102
Customer advances		124			119
Derivative liabilities		1,211			529
Pensions and benefits		2,119			2,061
Asset retirement obligations		3,323			3,241
Regulatory liabilities		3,391			3,328
Other deferred credits and other long-term liabilities		2,329			2,500

Total deferred credits and other liabilities		17,234			16,214

Total liabilities		31,960			30,438

Commitments and contingencies (Note 6)
Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued and outstanding at each date)		2,315			2,304
Accumulated other comprehensive income (loss)		(12	)		37
Retained earnings		7,879			7,500

Total Edison International's common shareholders' equity		10,182			9,841
Noncontrolling interests		6			258
Preferred and preference stock of utility not subject to mandatory redemption		907			907

Total equity		11,095			11,006

Total liabilities and equity	$	43,055		$	41,444

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Cash Flows		Edison International
		Six Months Ended June 30,
(in millions)		2010			2009

		(Unaudited)
Cash flows from operating activities:
Net income		$	606		$	275
Less: Income (loss) from discontinued operations			8			(4	)

Income from continuing operations			598			279
Adjustments to reconcile to net cash provided by operating activities:
	Depreciation, decommissioning and amortization		749			688
	Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)		74			86
	Other amortization		56			58
	Lease terminations and other		2			888
	Stock-based compensation		14			11
	Equity in (income) loss from partnerships and unconsolidated subsidiaries – net		(39	)		2
	Distributions and dividends from unconsolidated entities		39			5
	Deferred income taxes and investment tax credits		247			(1,315	)
	Income from leveraged leases		(2	)		(12	)
Changes in operating assets and liabilities:
	Receivables		13			65
	Inventory		(36	)		9
	Restricted cash		43			(188	)
	Margin and collateral deposits – net of collateral received		12			(29	)
	Other current assets		(346	)		35
	Rent payments in excess of levelized rent expense		(111	)		(113	)
	Accounts payable		(114	)		58
	Accrued taxes		(69	)		(377	)
	Other current liabilities		(164	)		(94	)
	Derivative assets and liabilities – net		806			(628	)
	Regulatory assets and liabilities – net		(720	)		761
	Proceeds from U.S. Treasury grants		92			—
	Other assets		(38	)		(106	)
	Other liabilities		(152	)		804
Operating cash flows from discontinued operations			8			(4	)

Net cash provided by operating activities			962			883

Cash flows from financing activities:
Long-term debt issued			651			939
Long-term debt issuance costs			(25	)		(24	)
Long-term debt repaid			(366	)		(194	)
Bonds repurchased			—			(219	)
Short-term debt financing – net			410			(2,066	)
Settlements of stock-based compensation – net			(2	)		—
Cash contributions from noncontrolling interests			—			1
Dividends and distributions to noncontrolling interests			(25	)		(55	)
Dividends paid			(205	)		(202	)

Net cash provided (used) by financing activities		$	438		$	(1,820	)

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Cash Flows	Edison International
	Six Months Ended June 30,
(in millions)	2010			2009

	(Unaudited)
Cash flows from investing activities:
Capital expenditures	$	(2,070	)	$	(1,540	)
Purchase of interest in acquired companies		(4	)		(7	)
Proceeds from termination of leases		—			1,420
Proceeds from sale of nuclear decommissioning trust investments		600			1,310
Purchases of nuclear decommissioning trust investments and other		(697	)		(1,415	)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment		44			12
Maturities and sale of short-term investments		5			3
Purchase of short-term investments		(1	)		(1	)
Investments in other assets		9			(60	)
Effect of consolidation and deconsolidation of variable interest entities		(91	)		—

Net cash used by investing activities		(2,205	)		(278	)

Net decrease in cash and equivalents		(805	)		(1,215	)
Cash and equivalents, beginning of period		1,673			3,916

Cash and equivalents, end of period	$	868		$	2,701

The accompanying notes are an integral part of these consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

Edison International's principal wholly owned subsidiaries are SCE, a rate-regulated electric utility that supplies electric energy to a 50,000 square-mile area of central, coastal and southern California; and EMG, a wholly owned competitive power generation subsidiary. EMG is a holding company whose subsidiaries and affiliates are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EMG's subsidiaries also conduct hedging and energy trading activities in competitive power markets.

Basis of Presentation

Edison International's significant accounting policies were described in Note 1 of "Edison International Notes to Consolidated Financial Statements" included in the 2009 Form 10-K. Edison International follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2010 as discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with such financial statements.

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and six-month periods ended June 30, 2010 are not necessarily indicative of the operating results for the full year.

Management has performed an evaluation of subsequent events through the date the financial statements were issued.

The December 31, 2009 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.

Cash and Equivalents

Cash equivalents included money market funds totaling $600 million and $1,457 million at June 30, 2010 and December 31, 2009, respectively. The carrying value of cash equivalents equals the fair value, as all investments have maturities of three months or less. For further discussion of money market funds, see Note 10.

Edison International temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. Edison International reclassified $201 million and $224 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at June 30, 2010 and December 31, 2009, respectively.

Earnings Per Share

Edison International computes EPS using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International's

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participating securities are stock-based compensation awards payable in common shares, including stock options, performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares. Stock options awarded during the period 2003 through 2006 received dividend equivalents. Stock options awarded prior to 2002 and after 2006 were granted without a dividend equivalent feature. EPS attributable to Edison International common shareholders was computed as follows:

	Three Months Ended June 30,						Six Months Ended June 30,


(in millions)	2010			2009			2010			2009

	(Unaudited)
Basic earnings (loss) per share – continuing operations:
Income (loss) from continuing operations attributable to common shareholders, net of tax	$	343		$	(9	)	$	572		$	238
Participating securities dividends		(2	)		—			(2	)		—

Income (loss) from continuing operations available to common shareholders	$	341		$	(9	)	$	570		$	238

Weighted average common shares outstanding		326			326			326			326

Basic earnings (loss) per share – continuing operations	$	1.05		$	(0.03	)	$	1.75		$	0.73

Diluted earnings (loss) per share – continuing operations:
Income (loss) from continuing operations available to common shareholders	$	341		$	(9	)	$	570		$	238
Income impact of assumed conversions		1			—			1			—

Income (loss) from continuing operations available to common shareholders and assumed conversions	$	342		$	(9	)	$	571		$	238

Weighted average common shares outstanding		326			326			326			326
Incremental shares from assumed conversions		1			1			1			1

Adjusted weighted average shares – diluted		327			327			327			327

Diluted earnings (loss) per share – continuing operations	$	1.05		$	(0.03	)	$	1.75		$	0.73

Stock-based compensation awards to purchase 9,645,334 and 8,641,695 shares of common stock for the three months ended June 30, 2010 and 2009, respectively, and 6,080,199 and 8,641,695 shares of common stock for the six months ended June 30, 2010 and 2009, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares; and therefore, the effect would have been antidilutive.

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Inventory

Inventory is stated at the lower of cost or market, cost being determined by the weighted-average cost method for fuel, and the average cost method for materials and supplies. Inventory at June 30, 2010 and December 31, 2009 consisted of the following:

(in millions)	June 30, 2010		December 31, 2009


	(Unaudited)
Coal, gas, fuel oil and raw materials	$	186	$	158
Spare parts, materials and supplies		370		375

Total	$	556	$	533

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers and cash received from counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the value of the positions. Edison International presents margin and cash collateral deposits subject to a master netting arrangement netted with its derivative positions on its consolidated balance sheets. The following table summarizes margin and collateral deposits provided to and received from counterparties:

(in millions)		June 30, 2010		December 31, 2009


		(Unaudited)
Collateral provided to counterparties:
	Offset against derivative liabilities	$	34	$	49
	Reflected in margin and collateral deposits		111		125
Collateral received from counterparties:
	Offset against derivative assets		55		124
	Reflected in other current liabilities		57		59

New Accounting Guidance

Accounting Guidance Adopted in 2010

Consolidation – Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

The FASB issued an accounting standards update that changes how a company determines when an entity, that is insufficiently capitalized or is not controlled through voting (or similar rights), should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an ability to direct the activities of the entity that most significantly impact the entity's economic performance and whether the entity has an obligation to absorb losses or the right to receive expected returns of the entity. This guidance requires a company to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. Edison International adopted this guidance prospectively effective January 1, 2010. The impact of adopting this guidance resulted in the deconsolidation of assets totaling $683 million and the consolidation of assets totaling $99 million at January 1, 2010, and resulted in a cumulative effect adjustment which increased retained earnings by $15 million. For further discussion, see Note 13.

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Fair Value Measurements and Disclosures

The FASB issued an accounting standards update that provides for new disclosure requirements related to fair value measurements. The requirements, which Edison International adopted effective January 1, 2010, include separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. The update also clarified existing disclosure requirements for the level of disaggregation, inputs and valuation techniques. In addition, effective January 1, 2011, the Level 3 reconciliation of fair value measurements using significant unobservable inputs should include gross rather than net information about purchases, sales, issuances and settlements. The guidance impacts disclosures only. For further discussion, see Note 10.

Accounting Guidance Not Yet Adopted

In October 2009, the FASB issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenue based on those separate deliverables. This update also requires additional disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is effective beginning January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. Edison International is currently assessing the effects this guidance may have on its consolidated financial statements.

Note 2. Derivative Instruments and Hedging Activities

Electric Utility

Commodity Price Risk

SCE is exposed to commodity price risk, which represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's hedging program reduces ratepayer exposure to variability in market prices related to SCE's power and gas activities. As part of this program, SCE enters into energy options, swaps, forward arrangements, tolling arrangements and congestion revenue rights ("CRRs"). These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans. SCE recovers its related hedging costs through the ERRA balancing account and as a result, exposure to commodity price risk is not expected to impact earnings, but may impact cash flows.

SCE's electricity price exposure arises from energy produced and sold in the MRTU market as a result of differences between SCE's load requirements versus the amount of energy delivered from its generating facilities, existing bilateral contracts and CDWR contracts allocated to SCE.

A portion of SCE's purchased power supply is subject to natural gas price volatility. SCE's natural gas price exposure arises from purchasing natural gas for generation at Mountainview and peaker plants, from bilateral contracts where pricing is based on natural gas prices (this includes contract energy prices for most renewable QFs which are based on the monthly index price of natural gas delivered at the southern California border), and power contracts in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.

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Notional Volumes of Derivative Instruments

The following table summarizes the notional volumes of derivatives used for hedging activities:

		Economic Hedges

Commodity	Unit of Measure	June 30, 2010		December 31, 2009
		(Unaudited)

Electricity options, swaps and forward arrangements	GWh		14,686		14,868
Natural gas options, swaps and forward arrangements	Bcf		278		266
Congestion revenue rights	GWh		165,097		195,367
Tolling arrangements ¹	GWh		116,398		116,398

¹: In compliance with a CPUC mandate, SCE held an open, competitive solicitation that produced agreements with different project developers who have agreed to construct new southern California generating resources. SCE has entered into a number of contracts which are recorded as derivative instruments. The contracts provide for fixed capacity payments as well as pricing for energy delivered based on a heat rate and contractual operation and maintenance prices. However, due to uncertainty regarding the availability of required emission credits, some of the new generating resources may not be constructed and the contracts associated with these resources could therefore terminate, at which time SCE would no longer account for these contracts as derivatives.

Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at June 30, 2010:

	Derivative Assets						Derivative Liabilities


(in millions)	Short- Term		Long- Term		Subtotal		Short- Term		Long- Term		Subtotal		Net Liability

	(Unaudited)
Non-trading activities:
Economic hedges	$	78	$	197	$	275	$	187	$	1,188	$	1,375	$	1,100
Netting and collateral		—		—		—		8		—		8		8

Total	$	78	$	197	$	275	$	179	$	1,188	$	1,367	$	1,092

The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2009:

	Derivative Assets						Derivative Liabilities


(in millions)	Short- Term		Long- Term		Subtotal		Short- Term		Long- Term		Subtotal		Net Liability

	(Unaudited)
Non-trading activities:
Economic hedges	$	160	$	187	$	347	$	102	$	496	$	598	$	251

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Income Statement Impact of Derivative Instruments

SCE recognizes realized gains and losses on derivative instruments as purchased-power expense and recovers these costs, subject to reasonableness, from ratepayers. As a result, realized gains and losses are not reflected in earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are recorded as regulatory assets or liabilities and therefore are not reflected in earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.

The following table summarizes the components of economic hedging activity:

	Three Months Ended June 30,						Six Months Ended June 30,


(in millions)	2010			2009			2010			2009

	(Unaudited)
Realized gains/(losses)	$	(38	)	$	(96	)	$	(62	)	$	(194	)
Unrealized gains/(losses)		(276	)		293			(857	)		626

Contingent Features/Credit-Related Exposure

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. SCE has historically provided collateral in the form of cash and/or letters of credit for the benefit of counterparties. These requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments, and other factors.

Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from each of the major credit rating agencies, referred to as a "credit-risk-related contingent feature." If SCE's credit rating were to fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The aggregate fair value of all derivative liabilities with these credit-risk-related contingent features was $232 million and $91 million, as of June 30, 2010 and December 31, 2009, respectively, for which SCE has posted no collateral to its counterparties. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2010, SCE would be required to post $20 million of additional collateral.

Competitive Power Generation

EMG uses derivative instruments to reduce exposure to market risks that arise from fluctuations in prices of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EMG's financial results can be affected by fluctuations in interest rates. To the extent that EMG does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements.

Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not designated as cash flow hedges. Economic hedges are accounted for at fair value on EMG's consolidated balance sheets with offsetting changes recorded in the consolidated statements of income (loss). For transactions that qualify for accounting hedge treatment, the fair value is recognized, to the extent effective, on EMG's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive income until the related forecasted transaction occurs.

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Derivative instruments that are utilized for trading purposes are measured at fair value and included in the balance sheets as derivative assets or liabilities. Changes in fair value are recognized in the consolidated statements of income (loss).

Notional Volumes of Derivative Instruments

The following table summarizes the notional volumes of derivatives used for hedging and trading activities:

June 30, 2010

				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges			Economic Hedges			Trading Activities

				(Unaudited)
Electricity	Forwards/Futures	Sales	GWh		29,884	¹		19,257	³		33,785
Electricity	Forwards/Futures	Purchases	GWh		408	¹		18,698	³		36,700
Electricity	Capacity	Sales	MW-Day (in thousands)		183	²		—			218	²
Electricity	Capacity	Purchases	MW-Day (in thousands)		17	²		—			557	²
Electricity	Congestion	Sales	GWh		—			136	⁴		8,964	⁴
Electricity	Congestion	Purchases	GWh		—			1,362	⁴		195,038	⁴
Natural gas	Forwards/Futures	Sales	bcf		—			1.5			45.0
Natural gas	Forwards/Futures	Purchases	bcf		—			—			47.9
Fuel oil	Forwards/Futures	Sales	barrels		—			120,000			319,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			495,000			329,000
Coal	Forwards/Futures	Sales	tons		—			—			1,095,000
Coal	Forwards/Futures	Purchases	tons		—			—			465,000

(in millions)

Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date

			(Unaudited)
Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt	Cash flow	$	145	June 2016
Amortizing forward starting interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt	Cash flow		122	December 2025

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December 31, 2009


				Hedging Activities

Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges			Economic Hedges			Trading Activities

				(Unaudited)
Electricity	Forwards/Futures	Sales	GWh		24,355	¹		26,838	³		23,306
Electricity	Forwards/Futures	Purchases	GWh		106	¹		25,971	³		23,404
Electricity	Capacity	Sales	MW-Day (in thousands)		254	²		1	²		597	²
Electricity	Capacity	Purchases	MW-Day (in thousands)		11	²		2	²		736	²
Electricity	Congestion	Sales	GWh		—			136	⁴		10,212	⁴
Electricity	Congestion	Purchases	GWh		—			1,576	⁴		181,930	⁴
Natural gas	Forwards/Futures	Sales	bcf		—			3.3			30.8
Natural gas	Forwards/Futures	Purchases	bcf		—			—			30.6
Fuel oil	Forwards/Futures	Sales	barrels		—			250,000			120,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			625,000			120,000

(in millions)

Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date

			(Unaudited)
Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt	Cash flow	$	160	June 2016

¹: EMG's hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power contracts for the fossil-fueled facilities which meet the normal sales and purchase exception and are accounted for on the accrual method.
²: EMG's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM RPM auction is not accounted for as a derivative.
³: EMG also entered into transactions that adjust financial and physical positions, or day-ahead and real-time positions to reduce costs or increase gross margin. These positions largely offset each other. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.
⁴: Congestion contracts include financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.

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Fair Value of Derivative Instruments

The following table summarizes the fair value of derivative instruments reflected on EMG's consolidated balance sheets:

June 30, 2010

		Derivative Assets									Derivative Liabilities

																				Net Assets
(in millions)		Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal			Net Assets

Non-trading activities
	Cash flow hedges	$	153		$	14		$	167		$	39		$	43		$	82		$	85
	Economic hedges		111			3			114			93			2			95			19
Trading activities			237			121			358			182			50			232			126

			501			138			639			314			95			409			230
Netting and collateral received ¹			(355	)		(59	)		(414	)		(314	)		(72	)		(386	)		(28	)

Total		$	146		$	79		$	225		$	—		$	23		$	23		$	202


December 31, 2009
		Derivative Assets									Derivative Liabilities

																				Net Assets
(in millions)		Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal			Net Assets

		(Unaudited)
Non-trading activities
	Cash flow hedges	$	240		$	17		$	257		$	69		$	6		$	75		$	182
	Economic hedges		202			8			210			180			—			180			30
Trading activities			234			111			345			182			41			223			122

			676			136			812			431			47			478			334
Netting and collateral received ¹			(479	)		(55	)		(534	)		(426	)		(32	)		(458	)		(76	)

Total		$	197		$	81		$	278		$	5		$	15		$	20		$	258

¹: Netting of derivative receivables and derivative payables and the related cash collateral received and paid is permitted when a legally enforceable master netting agreement exists with a derivative counterparty.

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Income Statement Impact of Derivative Instruments

The following table provides the activity of accumulated other comprehensive income, containing the information about the changes in the fair value of cash flow hedges and reclassification from accumulated other comprehensive income into results of operations:

	Cash Flow Hedge Activity ¹ Six Months Ended June 30,

	Cash Flow Hedge Activity ¹ Six Months Ended June 30,						Income Statement Location
(in millions)	2010			2009			Income Statement Location

	(Unaudited)
Accumulated other comprehensive income derivative gain at January 1	$	175		$	398
Effective portion of changes in fair value		30			109
Reclassification from accumulated other comprehensive income to net income		(122	)		(55	)	Competitive power generation revenue

Accumulated other comprehensive income derivative gain at June 30	$	83		$	452

¹: Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at June 30, 2010 and 2009 were $50 million and $269 million, respectively.

The portion of a cash flow hedge that does not offset the change in the value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings.

EMG recorded a net gain (loss) of $(7) million and $5 million during the second quarters of 2010 and 2009, respectively, and $1 million and $5 million during the six months ended June 30, 2010 and 2009, respectively, representing the amount of cash flow hedge ineffectiveness and are reflected in operating revenues on the consolidated statements of income (loss).

The effect of realized and unrealized gains (losses) from derivative instruments used for economic hedging and trading purposes on the consolidated statements of income (loss) is presented below:

		Three Months Ended June 30,					Six Months Ended June 30,


	Income Statement Location
(in millions)	Income Statement Location	2010			2009		2010			2009

		(Unaudited)
Economic hedges	Operating revenue	$	(3	)	$	3	$	(7	)	$	16
	Fuel expense		(2	)		14		(1	)		14
Trading activities	Operating revenue		33			17		80			27

Contingent Features/Credit Related Exposure

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses and unrealized gains in connection with derivative activities. Certain derivative contracts do not require margin, but contain provisions that require EME or Midwest Generation to

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comply with the terms and conditions of their respective credit facilities. The credit facilities each contain financial covenants. Some hedge contracts include provisions related to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions may result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT has hedge contracts that do not require margin, but provide that each party can request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at June 30, 2010 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME, Midwest Generation or EMMT to termination payments or additional collateral postings under the contingent features described above.

Note 3. Liabilities and Lines of Credit

Long-Term Debt

In March 2010, SCE issued $500 million of 5.5% first and refunding mortgage bonds due in 2040. In May 2010, SCE reissued $144 million of 5.0% tax-exempt pollution control bonds due in 2035. The proceeds from these bonds were used to repay commercial paper borrowings and for general corporate purposes.

EMG consolidated the Ambit project on January 1, 2010. At June 30, 2010, this project had $71 million of bonds payable, which are supported by a letter of credit. Principal payments are due annually through October 1, 2017. Interest rates are reset weekly based on current bond yields for similar securities. The average interest rate for the six months ended June 30, 2010 was 0.26%. Annual maturities of this debt at June 30, 2010 for the next five years are summarized as follows: $8 million in 2010, $8 million in 2011, $9 million in 2012, $10 million in 2013, and $10 million in 2014. In January 2010, Edison Capital repaid in full its medium-term loans. The balance of these loans was $89 million at December 31, 2009.

Credit Agreements and Short-Term Debt

In March 2010, SCE replaced its $500 million 364-day revolving credit facility with a new $500 million three-year credit facility that terminates in March 2013.

SCE's short-term debt is generally used to finance fuel inventories, balancing account under-collections and general, temporary cash requirements including power purchase payments. At June 30, 2010, the outstanding short-term debt was $215 million at a weighted-average interest rate of 0.42%. This short-term debt is supported by $2.9 billion of credit lines. At December 31, 2009, the outstanding short-term debt was zero.

In March 2010, EMG completed through its subsidiary, Cedro Hill Wind, LLC, a non-recourse financing of its interests in the Cedro Hill wind project. The financing included a $135 million construction loan that is required to be converted to a 15-year amortizing term loan by May 31, 2011, subject to meeting specified conditions. As of June 30, 2010, there was $65 million outstanding under the construction loan at a weighted average interest rate of 3.35%.

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Edison International (parent) short-term debt is generally used to finance operating expenses and dividends. At June 30, 2010, the outstanding short-term debt was $215 million at a weighted-average interest rate of 0.71%. At December 31, 2009, the outstanding short-term debt was $85 million at a weighted-average interest rate of 0.60%.

Letters of Credit

As of June 30, 2010, letters of credit issued under EME and its subsidiaries' credit facilities aggregated $129 million and are scheduled to expire as follows: $36 million in 2010 and $93 million in 2011. Letters of credit issued under SCE's credit facilities aggregated $11 million and are scheduled to expire in 2010.

Note 4. Income Taxes

The table below contains a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations attributable to common shareholders:

		Three Months Ended June 30,						Six Months Ended June 30,


(in millions)		2010			2009			2010			2009

		(Unaudited)
Provision for income tax at federal statutory rate of 35%		$	72		$	(187	)	$	205		$	(58	)
Increase (decrease) in income tax from:
Items presented with related state income tax, net
	Global Settlement related		(138	)		(298	)		(138	)		(298	)
	Change in tax accounting method for asset removal costs		(40	)		—			(40	)		—
State tax – net of federal benefit			16			(13	)		23			(4	)
Health care legislation			—			—			39			—
Production and housing credits			(19	)		(16	)		(34	)		(34	)
Property-related and other			(27	)		(10	)		(41	)		(8	)

Total income tax expense from continuing operations		$	(136	)	$	(524	)	$	14		$	(402	)

Pre-tax income from continuing operations		$	207		$	(533	)	$	586		$	(164	)

Effective tax rate			(66%	)		98%			2%			245%

The CPUC requires flow-through rate-making treatment for the current tax benefit arising from certain property-related and other temporary differences which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.

Global Settlement

During the second quarter of 2010, Edison International recognized a $138 million earnings benefit resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002 (described in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K) and revision to interest recorded on the federal Global Settlement. Edison International is awaiting receipt of final interest calculations from the California Franchise Tax Board.

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During the six months ended June 30, 2009, Edison International recorded a consolidated after-tax earnings charge of $274 million related to the Global Settlement finalized with the IRS and termination of Edison Capital's cross-border leases ($920 million pre-tax loss).

Change in Tax Accounting Method for Asset Removal Costs

During the second quarter of 2010, the IRS approved Edison International's request to change its tax accounting method for asset removal costs primarily related to SCE's infrastructure replacement program. As a result, Edison International recognized a $40 million earnings benefit ($28 million of which relates to asset removal costs incurred prior to 2010) from deducting asset removal costs earlier in the construction cycle. These deductions are recorded on a flow-through basis.

Health Care Legislation

During the first quarter of 2010, Edison International recognized a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010. The Patient Protection and Affordable Care Act, as modified by the Health Care and Education Reconciliation Act, includes a provision that eliminates the federal tax deduction of retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies. Although this change does not take effect until January 1, 2013, Edison International is required to recognize the full accounting impact of the legislation in its financial statements in the period of enactment.

Accounting for Uncertainty in Income Taxes

Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits from January 1 to June 30 for 2010 and 2009:

(in millions)	2010			2009


	(Unaudited)
Balance at January 1	$	664		$	2,237
Tax positions taken during the current year:
Increases		35			87
Tax positions taken during a prior year:
Increases		127			148
Decreases		(40	)		(26	)
Decreases for settlements during the period		(82	)		(1,807	)

Balance at June 30	$	704		$	639

As of June 30, 2010 and December 31, 2009, respectively, if recognized, $335 million and $374 million of unrecognized tax benefits would impact the effective tax rate.

Accrued Interest and Penalties

The total amount of accrued interest and penalties related to Edison International's income tax liabilities was $278 million and $380 million as of June 30, 2010 and December 31, 2009, respectively.

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The after-tax interest income recognized and included in income tax expense was $101 million and $113 million for the three months ended June 30, 2010 and 2009, respectively, and was $88 million and $109 million for the six months ended June 30, 2010 and 2009, respectively.

Note 5. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

During the six months ended June 30, 2010, Edison International made 2010 plan year contributions of $57 million and expects to make $51 million of additional contributions during the remainder of 2010. SCE recovers contributions made to most of its pension plans through CPUC-approved regulatory mechanisms. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.

Expense components are:

	Three Months Ended June 30,						Six Months Ended June 30,


(in millions)	2010			2009			2010			2009

	(Unaudited)
Service cost	$	34		$	32		$	68		$	63
Interest cost		54			52			108			103
Expected return on plan assets		(52	)		(42	)		(104	)		(83	)
Amortization of prior service cost		2			4			4			8
Amortization of net loss		7			14			14			28

Expense under accounting standards	$	45		$	60		$	90		$	119
Regulatory adjustment – deferred		(14	)		(37	)		(28	)		(73	)

Total expense recognized	$	31		$	23		$	62		$	46

Postretirement Benefits Other Than Pensions

During the six months ended June 30, 2010, Edison International made 2010 plan year contributions of $18 million and expects to make $33 million of additional 2010 plan year contributions during the remainder of 2010. SCE's annual contributions are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to its total annual expense.

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Expense components are:

	Three Months Ended June 30,						Six Months Ended June 30,


(in millions)	2010			2009			2010			2009

	(Unaudited)
Service cost	$	8		$	11		$	16		$	22
Interest cost		31			36			62			72
Expected return on plan assets		(25	)		(21	)		(50	)		(42	)
Amortization of prior service cost (credit)		(9	)		(8	)		(18	)		(15	)
Amortization of net loss		8			16			16			31

Total expense	$	13		$	34		$	26		$	68

Stock-Based Compensation

During the first quarter of 2010, Edison International granted its 2010 stock-based compensation awards, which included stock options, performance shares and restricted stock units. Total stock-based compensation expense (reflected in the caption "Other operation and maintenance" on the consolidated statements of income (loss)) was $9 million and $10 million for the three months ended June 30, 2010 and 2009, respectively, and was $17 million and $16 million for the six months ended June 30, 2010 and 2009, respectively. The income tax benefit recognized in the consolidated statements of income (loss) was $4 million for the three months ended June 30, 2010 and 2009, and was $7 million and $6 million for the six months ended June 30, 2010 and 2009, respectively. Consistent with SCE's 2009 GRC, no stock-based compensation has been capitalized since December 31, 2008. Excess tax benefits included in "Settlements of stock-based compensation – net" in the financing section of the consolidated statements of cash flows were $2 million and $4 million for the six months ended June 30, 2010 and 2009, respectively.

Stock Options

The following is a summary of the status of Edison International stock options:

				Weighted-Average


	Stock options			Exercise Price		Remaining Contractual Term (Years)		Aggregate Intrinsic Value

	(Unaudited)
Outstanding at December 31, 2009		17,368,032		$	32.15
Granted		3,714,111			33.26
Expired		(18,661	)		45.74
Forfeited		(146,821	)		31.09
Exercised		(377,107	)		22.59

Outstanding at June 30, 2010		20,539,554			32.52		6.58

Vested and expected to vest at June 30, 2010		20,034,692			32.53		6.52	$	77,846,571

Exercisable at June 30, 2010		11,854,616			32.55		5.01		55,789,066

Cash outflows to purchase Edison International shares in the open market to settle stock option exercises were $6 million and $1 million for the three months ended June 30, 2010 and 2009,

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respectively, and were $13 million and $6 million for the six months ended June 30, 2010 and 2009, respectively. Cash inflows from participants to exercise stock options were $4 million and $1 million for the three months ended June 30, 2010 and 2009, respectively, and were $9 million and $4 million for the six months ended June 30, 2010 and 2009, respectively. The tax benefit realized from options exercised was $1 million and less than $1 million for the three months ended June 30, 2010 and 2009, respectively, and $2 million and $1 million for the six months ended June 30, 2010 and 2009, respectively.

Performance Shares

The following is a summary of the status of Edison International nonvested performance shares classified as equity awards:

	Performance Shares			Weighted-Average Grant-Date Fair Value


	(Unaudited)
Nonvested at December 31, 2009		343,452		$ 35.41
Granted		140,487		32.36
Forfeited		(68,925	)	55.62

Nonvested at June 30, 2010		415,014		31.02

The following is a summary of the status of Edison International nonvested performance shares classified as liability awards (the current portion is reflected in the caption "Other current liabilities" and the long-term portion is reflected in "Accumulated provision for pensions and benefits" on the consolidated balance sheets):

	Performance Shares			Weighted-Average Fair Value


	(Unaudited)
Nonvested at December 31, 2009		343,452
Granted		140,487
Forfeited		(68,925	)

Nonvested at June 30, 2010		415,014		$ 18.83

There were no performance shares settled in 2009 or 2010.

Note 6. Commitments and Contingencies

Commitments

SCE entered into a 20-year power purchase contract which is classified as a capital lease and is expected to be recorded on the consolidated balance sheets upon commencement of the contract in 2013. SCE's commitments upon commencement are estimated to be: $23 million in 2013, $44 million in 2014, and $805 million for the remaining period thereafter.

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Other Commitments

At June 30, 2010, SCE had power purchase contracts with additional commitments estimated to be: $67 million for the remainder of 2010, $83 million in 2011, $67 million in 2012, $39 million in 2013, $39 million in 2014, and $613 million for the remaining period thereafter.

At June 30, 2010, EMG's subsidiaries had firm commitments to spend approximately $447 million during the remainder of 2010 on capital and construction expenditures. These expenditures primarily relate to the construction of wind projects. EMG intends to fund these expenditures through project-level and turbine vendor financing, U.S. Treasury grants, cash on hand and cash generated from operations.

EMG has entered into various turbine supply agreements with vendors to support its wind development efforts. As of June 30, 2010, EME had commitments, excluding turbines subject to the legal dispute described below, to purchase 46 wind turbines (69 MW) and had 13 wind turbines (33 MW) in storage to be used for future wind projects. EMG has 59 wind turbines (102 MW) available for future projects, excluding turbines allocated to projects in construction and turbines subject to the legal dispute. EMG has payment commitments related to wind turbines of $85 million due in 2011. During the second quarter, EMG deferred the delivery and $82 million in payments for 69 MW of turbines to January 2011.

Excluded from the turbine agreements referred to above is a turbine supply agreement between Mitsubishi Power Systems Americas, Inc. and EME, which is subject to a legal dispute. EME has made deposits of $68 million for the purchase of 83 wind turbines (199 MW) under this agreement. The remaining payments under this agreement subject to dispute are $289 million, mostly related to undelivered wind turbines. Resolution of this dispute will impact whether, and to what extent, future payments may be due under this agreement.

At June 30, 2010, Midwest Generation and Homer City had fuel purchase commitments with various third-party suppliers for the purchase of coal. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses, these minimum commitments are estimated to aggregate $936 million, summarized as follows: $251 million for the remainder of 2010, $405 million in 2011, $247 million in 2012, and $33 million in 2013.

At June 30, 2010, Midwest Generation and Homer City each had contractual agreements for the transport of coal to their respective facilities. The commitments under these contracts are based on either actual coal purchases or minimum quantities. Accordingly, contractual obligations for transportation based on actual coal purchases are derived from committed coal volumes set forth in fuel supply contracts. The minimum commitments under these contracts are estimated to aggregate $314 million, summarized as follows: $143 million for the remainder of 2010, and $171 million in 2011.

In addition to the above, in July 2010, Midwest Generation entered into additional contracts for the purchase of coal. These commitments, together with the estimated transportation costs under the existing agreements, are estimated to be $101 million for 2011.

SCE and EME have letters of credit outstanding under their credit facilities. For further discussion, see Note 3.

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Guarantees and Indemnities

Edison International's subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, guarantees of debt and indemnifications.

Environmental Indemnities Related to the Midwest Generation Plants

In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Also, in connection with the sale-leaseback transaction related to the Powerton and Joliet Stations in Illinois, EME agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnities, a maximum potential liability cannot be determined. Commonwealth Edison has advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the litigation discussed below under "—Contingencies—Midwest Generation New Source Review Lawsuit." The sale-leaseback participants have requested similar indemnification. Except as discussed below, EME has not recorded a liability related to these environmental indemnities.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2011. There were approximately 217 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2010. Midwest Generation had recorded a $49 million liability at June 30, 2010 for previous, pending and future claims.

The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than projected.

Environmental Indemnity Related to the Homer City Facilities

In connection with the acquisition of the Homer City facilities, Homer City agreed to indemnify the sellers with respect to specified environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed this

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obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City facilities, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. For discussion of the NOV received by Homer City and associated indemnity claims, see "—Contingencies—Homer City New Source Review Notice of Violation." EME has not recorded a liability related to this indemnity.

Indemnities Provided under Asset Sale and Sale-Leaseback Agreements

The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At June 30, 2010, EME had recorded a liability of $39 million related to these matters.

In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. No significant amounts are recorded as a liability for these matters.

In connection with the sale-leaseback transactions related to the Homer City facilities in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April 2004, Midwest Generation's tax indemnity agreement with the former lease equity investor is still in effect. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. No significant amounts are recorded as a liability for these matters.

Indemnity Provided as Part of the Acquisition of Mountainview

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific environmental claims related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilities with respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.

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Mountainview Filter Cake Indemnity

The Mountainview power plant utilizes water from on-site groundwater wells and City of Redlands ("City") recycled water for cooling purposes. Unrelated to the operation of the plant, this water contains perchlorate. The pumping of the water removes perchlorate from the aquifer beneath the plant and concentrates it in the plant's wastewater treatment "filter cake." Use of this impacted groundwater for cooling purposes was mandated by Mountainview's California Energy Commission permit. SCE has indemnified the City for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this indemnity.

Other Edison International Indemnities

SCE provides other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and specified environmental indemnities and income taxes with respect to assets sold. SCE's obligations under these agreements may be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties for certain indemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overall maximum amount of the obligation under these indemnifications cannot be reasonably estimated. SCE has not recorded a liability related to these indemnities.

Contingencies

In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International believes that the outcome of these other proceedings will not materially affect its results of operations, financial position or liquidity.

Environmental Developments

Edison International is subject to numerous environmental laws and regulations, which typically require a lengthy and complex process for obtaining licenses, permits and approvals and require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.

Possible developments, such as the enactment of more stringent environmental laws and regulations, proceedings that may be initiated by environmental and other regulatory authorities, cases in which new theories of liability are recognized, and settlements agreed to by other companies that establish precedent or expectations for the power industry, could affect the costs and the manner in which business is conducted, and could cause substantial additional capital expenditures or operational expenditures or the ceasing of operations at certain facilities. There is no assurance that any additional costs arising from such developments would be recovered from customers or that Edison International's financial position, results of operations and cash flows would not be materially affected by these developments.

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Midwest Generation Environmental Compliance Plans and Costs

During the second quarter of 2010, Midwest Generation continued its permitting and planning activities for NO _x and SO ₂ controls to meet the requirements of the CPS. Midwest Generation has now received all necessary permits from the Illinois EPA allowing the installation of SNCR technology on multiple units to meet the NO _x portion of the CPS.

In addition, work continued on the possible employment of FGD technology using dry scrubbing with sodium-based sorbents as a method to comply with the SO ₂ portion of the CPS. Testing of this technology demonstrated significant reductions in SO ₂ emissions when using the low-sulfur coal employed by Midwest Generation. Use of this technology in combination with low-sulfur coal is expected to require substantially less capital and installation time than the spray dryer absorber technology originally contemplated, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants. Also, the use of dry scrubbing with sodium-based sorbents to meet environmental regulations will likely require Midwest Generation to incur the costs of upgrading its particulate removal systems.

Based on this work, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO ₂ emissions, at approximately $1.2 billion in 2010 dollars. If completed, these expenditures would be incurred over multiple years. Midwest Generation expects to seek permits from the Illinois EPA for select initial units later this year.

Decisions regarding whether or not to proceed with the above projects or other approaches to compliance remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation could also elect to shut down units, instead of installing controls, to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation may defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others.

Homer City Environmental Issues and Capital Resource Limitations

Homer City operates SCR equipment on all three units to reduce NO _x emissions, operates FGD equipment on Unit 3 to reduce SO ₂ emissions, and uses coal-cleaning equipment on site to reduce the ash and sulfur content of raw coal to meet both combustion and environmental requirements. Homer City may be required to install additional environmental equipment on Unit 1 and Unit 2 to comply with environmental regulations for future operations. For further information, see "—Transport Rule" and "—Homer City New Source Review Notice of Violation." Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Homer City will have limited ability to obtain additional outside capital for such projects without amending its lease and related agreements. EME is under no contractual obligation to provide funding to Homer City.

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Greenhouse Gas Regulation

On June 3, 2010, the US EPA finalized the PSD and Title V GHG tailoring rule. The effective date of the final rule is August 2, 2010. The emissions thresholds for CO2 equivalents in the final rule are as follows:



January – June 2011		75,000 tons per year for new and modified sources already subject to PSD for pollutants other than GHGs
July 2011 – June 2013		100,000 tons per year for new sources, and 75,000 tons per year for modified sources

Petitions for judicial review of the GHG tailoring rule are to be submitted by August 2, 2010. Legal challenges to the GHG tailoring rule have been filed.

Transport Rule

On July 6, 2010, the US EPA issued a Notice of Proposed Rulemaking for a proposed rule, known as the Transport Rule, which would require 31 eastern states (including Pennsylvania and Illinois) and the District of Columbia to substantially reduce power plant emissions of NO _x and SO ₂ starting in 2012, with additional reductions in 2014. The Transport Rule would replace the Clean Air Interstate Rule, which had been remanded to the US EPA in 2008 for issuance of a revised rule.

The US EPA has proposed three possible approaches to emissions allowance trading. Under its preferred approach, a pollution limit would be set for each state, intrastate trading would be permitted among power plants, and limited interstate trading would also be permitted consistent with the requirement that each state meet its own pollution control obligations. Under the first alternative, a pollution limit would be set for each state, and only intrastate trading of allowances would be permitted. Under the second alternative, a pollution limit would be set for each state and an emissions limit would be set for each power plant, and limited emissions averaging would be permitted among affected units.

Under the Transport Rule, each covered state would initially be subject to a federal implementation plan designed to reduce pollution that significantly contributed to nonattainment of, or interferes with the maintenance of, NAAQS in other states. States would be able to choose to develop state implementation plans to replace the federal implementation plans.

Comments on the Transport Rule will be due 60 days after its publication in the Federal Register. The Transport Rule is scheduled to be finalized in 2011. The Clean Air Interstate Rule will remain in place until that time. EME believes that the US EPA's preferred approach to emissions allowance trading would provide allowance allocations which are adequate for the Midwest Generation plants based on projected emissions using the Illinois CPS allowable emission rates. The proposed rule, if adopted, may require the installation of additional environmental equipment to reduce SO ₂ emissions at Units 1 and 2 of the Homer City facilities to continue to operate under the rule.

National Ambient Air Quality Standard for Sulfur Dioxide

On June 2, 2010, the US EPA finalized the primary NAAQS for SO ₂ by establishing a new one-hour standard at a level of 75 parts per billion. The final standard is in line with EME's expectations and is

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being taken into account in EME's environmental compliance strategy. Revisions to state implementation plans to achieve compliance with the new standard are due to be submitted to the US EPA by February 2014. The US EPA anticipates that the deadline for attainment with the SO ₂ NAAQS will be August 2017 (five years after the US EPA intends to finalize initial determinations as to the areas of the country that are and are not in attainment with the primary SO ₂ NAAQS).

Hazardous Substances and Hazardous Waste Laws

On June 21, 2010, the US EPA published proposed regulations relating to coal combustion wastes. Two different proposed approaches are under consideration. The first approach, under which the US EPA would list these wastes as special wastes subject to regulation under Subtitle C of the Resource Conservation and Recovery Act (the section for hazardous wastes), could require EME to incur additional capital and operating costs. The second approach, under which the US EPA would regulate these wastes under Subtitle D of the Resource Conservation and Recovery Act (the section for nonhazardous wastes), is substantially similar to the requirements of existing regulations.

California Renewable Energy Developments

In June 2010, CARB released a proposed Renewable Electricity Standard regulation, which would require most retail sellers of electricity in California to procure 33% of their electricity from eligible renewable energy resources by 2020. The California legislature is also contemplating legislation to adopt a 33% renewables portfolio standard that may supersede the CARB regulation and impose its own program structure. Due to the possibility of legislation, the CARB has postponed voting on its proposed regulation until September 2010 at the Governor's request. SCE believes that achieving a 33% renewables portfolio standard in this timeframe will be highly ambitious, given the magnitude of the infrastructure build-out required and the slow pace of transmission permitting and approvals.

Once-Through Cooling

In May 2010, the California State Water Resources Board issued a final policy, which establishes closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like San Onofre and many of the existing fossil-fueled power plants along the California coast. The final policy requires an independent engineering study to be conducted regarding the feasibility of compliance by California's two coastal nuclear power plants. Depending on the results of the study, the required compliance may result in significant capital expenditures at San Onofre and may affect its operations. It may also significantly impact SCE's ability to procure generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems, system reliability and the cost of electricity to the extent other coastal power plants in California are forced to shut down or limit operations. The policy has the potential to adversely affect California's nineteen once-through cooled power plants, which provide over 21,000 MW of combined, in-state generation capacity, including over 9,100 MW of capacity interconnected within SCE's service territory.

Environmental Remediation

Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include

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costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts.

As of June 30, 2010, Edison International's recorded estimated minimum liability to remediate its 28 identified sites at SCE (23 sites) and EME (5 sites primarily related to Midwest Generation) was $41 million, of which $38 million was related to SCE. Edison International's other subsidiaries have no identified remediation sites. The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs at these identified sites could exceed its recorded liability by up to $223 million, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 34 immaterial sites for which total liability ranges from $5 million (the recorded minimum liability) to $10 million.

The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $32 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $39 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $3 million to $18 million. Recorded costs were $3 million and $2 million for the three months ended June 30, 2010 and 2009, respectively, and were $3 million and $5 million for the six months ended June 30, 2010 and 2009, respectively.

Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

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Federal and State Income Taxes

Edison International's federal income tax returns are currently under examination by the IRS for tax years 2003 through 2006 and are subject to examination through tax year 2009. Edison International's California state income tax returns are subject to examination for tax years 1991 through 2009.

2010 FERC Rate Case

In September 2009, the FERC issued an order allowing SCE to implement its proposed 2010 rates effective March 1, 2010, subject to refund. The proposed rates would increase SCE's FERC revenue requirement by $107 million, or 24%, over the 2009 FERC revenue requirement primarily due to an increase in transmission rate base, and would result in an approximate 1% increase to SCE's overall system average rate. SCE has terminated settlement negotiations and begun the litigation process for the proposed 2010 rates. A final decision is expected in the second half of 2011.

FERC Transmission Incentives and CWIP Proceedings

In November 2007, the FERC issued an order granting ROE incentive adders, recovery of the ROE and incentive adders in the CWIP proceedings, and 100% recovery of abandoned plant costs (if any) for three of SCE's transmission projects: 125 basis point adder for both DPV2 and Tehachapi, and a 75 basis point adder for Rancho Vista. The CPUC filed an appeal of this order, which had been stayed pending final resolution by the FERC of the 2008 CWIP proceeding. In April 2010, the FERC issued an order on SCE's 2008 CWIP proceeding. The order sets SCE's 2008 base ROE (before incentives) at 9.54% and establishes a methodology for determining the base ROE for 2009 and 2010 CWIP incentives. In June 2010, SCE filed an application for rehearing with the FERC. The order did not have a material impact on SCE's earnings or cash flows. The outcomes of the 2009 and 2010 CWIP proceedings are still pending. SCE began collecting the 2010 CWIP revenue requirements in rates on June 1, 2010. The collected 2008 through 2010 CWIP revenue requirements are subject to refund, pending a final FERC order on these matters.

Homer City New Source Review Notice of Violation

Recent Developments

In May 2010, Homer City received an NOV from the US EPA. The new NOV alleges claims similar to those in the 2008 NOV, but it adds non-attainment NSR requirements to the alleged PSD violations. It also adds two prior owners of the Homer City facilities as parties.

In July 2010, Homer City received a 60-day Notice of Intent to Sue signed by the State of New York and the PADEP, stating their intent to file a citizen suit based on the same or similar theories advanced by the US EPA in the NOV. The Notice of Intent to Sue also named the sale-leaseback owner participants of the Homer City facilities, Homer City's general partner and limited partner, and two prior owners of the Homer City facilities.

Background

In June 2008, Homer City received an NOV from the US EPA alleging that, beginning in 1988, Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the PSD requirements of the CAA. The US EPA also alleges that Homer City has failed to file timely and

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complete Title V permits. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. On June 30, 2009 and January 2, 2010, the US EPA issued requests for information to Homer City under Section 114 of the CAA. Homer City is working on a response to the requests. Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. EME cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.

Homer City has sought indemnification for liability and defense costs associated with the NOV from the sellers under the asset purchase agreement pursuant to which Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting a portion of defense costs related to the claims.

Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV under the operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer City facilities, in turn, sought indemnification and defense from Homer City for costs and liabilities associated with the Homer City NOV. Homer City responded by recognizing its indemnity obligation and defense of the claims on terms consistent with its contractual obligations.

Midwest Generation New Source Review Lawsuit

Recent Developments

In March 2010, the Federal District Court for the Northern District of Illinois dismissed nine of the ten counts related to PSD requirements in the complaint filed by the US EPA and the State of Illinois against Midwest Generation, holding that, as a subsequent owner, Midwest Generation could not be held liable under the PSD provisions for modifications allegedly made by Commonwealth Edison, the prior owner of the Midwest Generation plants. The Court also dismissed the tenth count to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. The decision did not address (i) other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA or (ii) the complaint in intervention filed by a group of Chicago-based environmental action groups, which also alleges opacity and particulate matter violations.

In April 2010, the US EPA formally issued to EME the same NOV that was issued to Midwest Generation in 2007. The transmittal letter stated that the action was based on a review of the asset purchase agreement for the Midwest Generation plants and that the NOV was being issued to EME as a successor in interest to Commonwealth Edison.

In June 2010, the US EPA, the State of Illinois, and several the environmental groups filed amended complaints in the New Source Review litigation. The amended complaints are similar to the prior complaints, but seek to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. An August status hearing has been scheduled, at which time a schedule for responses -to the amended complaints and other procedural matters will be determined.

Background

In August 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or

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replacement projects at six Illinois coal-fired electric generating stations in violation of the PSD requirements and of the New Source Performance Standards of the CAA, including alleged requirements to obtain a construction permit and to install controls sufficient to meet BACT emissions rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. At approximately the same time, Commonwealth Edison received an NOV substantially similar to the Midwest Generation NOV. Midwest Generation, Commonwealth Edison, the US EPA, and the DOJ, along with several Chicago-based environmental action groups, had discussions designed to explore the possibility of a settlement but no settlement resulted.

In August 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging claims substantially similar to those in the NOV. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or New Source Review permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies sought by the plaintiffs in the lawsuit could go well beyond those required under the CPS. By order dated January 19, 2010, the Court allowed a group of Chicago-based environmental action groups to intervene in the case.

The owner participants of the Powerton and Joliet Stations have sought indemnification and defense from Midwest Generation and/or EME for costs and liabilities associated with these matters. EME responded by recognizing its indemnity obligation and defense of the claims on terms consistent with its contractual obligations.

An adverse decision could involve penalties and remedial actions that would have a material adverse impact on the financial condition and results of operations of EME. EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.

Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 against SCE, among other defendants, arising out of the coal supply agreement for Mohave. Subsequently, the Hopi Tribe was added as an additional plaintiff. As amended in April 2010, the Navajo Nation's complaint asserts claims for, among other things, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The complaint claims that the defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The complaint seeks damages of not less than $600 million, plus interest thereon, and punitive damages of not less than $1 billion. In April 2009, in a related case filed in December 1993 against the U.S. Government, the U.S. Supreme Court found that the Navajo Nation did not have a claim for compensation. No trial date has been set for this litigation. SCE cannot predict the outcome of the Tribes' complaints against SCE.

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Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $12.6 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($375 million). The balance is covered by a loss sharing program among nuclear reactor licensees. If a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site, all nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.

Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately $35 million per incident in any one year. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $43 million per year. Insurance premiums are charged to operating expense.

Spent Nuclear Fuel

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to begin acceptance of spent nuclear fuel by January 31, 1998. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim storage for spent nuclear fuel on site sufficient for the current license period.

In January 2004, SCE, as operating agent, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. In June 2010, the United States Court of Federal Claims issued a decision granting SCE damages of approximately $142 million to recover costs incurred through December 31, 2005. Additional legal action would be necessary to recover damages incurred after that date. The decision is subject to appeal by the DOE. Any damages recovered would be returned to SCE ratepayers or used to offset past or future fuel decommissioning or storage costs for the benefit of the ratepayer.

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Note 7. Consolidated Statements of Changes in Equity

The following table provides the changes in equity for the six months ended June 30, 2010:

	Equity Attributable to Edison International											Noncontrolling Interests


(in millions)	Common Stock		Accumulated Other Comprehensive Income			Retained Earnings			Subtotal			Other			Preferred and Preference Stock			Total Equity

	(Unaudited)
Balance at December 31, 2009	$	2,304	$	37		$	7,500		$	9,841		$	258		$	907		$	11,006
Net income		—		—			580			580			—			26			606
Other comprehensive loss		—		(49	)		—			(49	)		—			—			(49	)
Deconsolidation of variable interest entities		—		—			—			—			(249	)		—			(249	)
Cumulative effect of a change in accounting principle, net of tax		—		—			15			15			—			—			15
Common stock dividends declared ($0.63 per share)		—		—			(205	)		(205	)		—			—			(205	)
Dividends, distributions to noncontrolling interests and other		—		—			—			—			(3	)		(26	)		(29	)
Stock-based compensation – net		2		—			(4	)		(2	)		—			—			(2	)
Noncash stock-based compensation and other		9		—			(7	)		2			—			—			2

Balance at June 30, 2010	$	2,315	$	(12	)	$	7,879		$	10,182		$	6		$	907		$	11,095

The following table provides the changes in equity for the six months ended June 30, 2009:

	Equity Attributable to Edison International										Noncontrolling Interests


(in millions)	Common Stock		Accumulated Other Comprehensive Income		Retained Earnings			Subtotal			Other			Preferred and Preference Stock			Total Equity

	(Unaudited)
Balance at December 31, 2008	$	2,272	$	167	$	7,078		$	9,517		$	285		$	907		$	10,709
Net income		—		—		234			234			16			25			275
Other comprehensive income		—		37		—			37			—			—			37
Common stock dividends declared ($0.62 per share)		—		—		(202	)		(202	)		—			—			(202	)
Dividends, distributions to noncontrolling interests and other		—		—		—			—			(26	)		(25	)		(51	)
Stock-based compensation – net		2		—		(2	)		—			—			—			—
Noncash stock-based compensation and other		11		—		(7	)		4			—			—			4

Balance at June 30, 2009	$	2,285	$	204	$	7,101		$	9,590		$	275		$	907		$	10,772

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Note 8. Accumulated Other Comprehensive Income

Edison International's accumulated other comprehensive income consists of:

(in millions)	Cash Flow Hedges – Net Unrealized Gain (Loss)			Pension and PBOP – Net Gain (Loss)			Pension and PBOP – Prior Service Cost		Accumulated Other Comprehensive Income (Loss)


	(Unaudited)
Balance at December 31, 2009	$	105		$	(70	)	$	2	$	37
Current period change		(55	)		6			—		(49	)

Balance at June 30, 2010	$	50		$	(64	)	$	2	$	(12	)

Included in accumulated other comprehensive income at June 30, 2010 was $60 million, net of tax, in unrealized gains on EMG's commodity-based cash flow hedges; and a $10 million, net of tax, unrealized loss related to interest rate hedges. EMG's unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. Approximately $67 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which a commodity cash flow hedge is designated is through December 31, 2012.

Note 9. Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

			Six Months Ended June 30,

(in millions)			2010			2009

			(Unaudited)
Cash payments for interest and taxes
	Interest – net of amounts capitalized		$	305		$	314
	Tax payments			179			198
Noncash investing and financing activities
	Details of debt exchange:
		Pollution-control bonds redeemed	$	(203	)	$	—
		Pollution-control bonds issued		203			—
	Consolidation of variable interest entities:
		Assets other than cash	$	94		$	—
		Liabilities and non-controlling interests		99			—
	Deconsolidation of variable interest entities:
		Assets other than cash	$	380		$	—
		Liabilities and non-controlling interests		476			—
Dividends declared but not paid
	Common stock		$	103		$	101
	Preferred and preference stock of utility not subject to mandatory redemption			13			13

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Note 10. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value for a liability should reflect the entity's nonperformance risk. Fair value is determined using a hierarchy to prioritize the inputs to valuation models. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are:

Level 1—Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets and liabilities;

Level 2—Pricing inputs that include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument; and

Level 3—Prices or valuations that require inputs that are both significant to the fair value measurements and unobservable.

Edison International's assets and liabilities carried at fair value primarily consist of derivative contracts, SCE nuclear decommissioning trust investments and money market funds. Derivative contracts are primarily commodity contracts for the purchase and sale of power and gas and include contracts for forward physical sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange or over-the-counter traded.

The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. Investments in money market funds are generally classified as Level 1, as fair value is determined by observable market prices in active markets.

EMG's derivative contracts, valued based on forward market prices in active markets (PJM West Hub, Northern Illinois Hub peak and AEP/Dayton) adjusted for nonperformance risks, are classified as Level 2. EMG obtains forward market prices from traded exchanges (Intercontinental Exchange Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EMG selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EMG believes to provide the most liquid market for the commodity. EMG considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers and comparison to executed trades.

SCE's Level 2 derivatives primarily consist of natural gas financial swaps and natural gas physical trades for which SCE obtains the applicable Henry Hub, basis, index, or forward market prices from the New York Mercantile Exchange and Intercontinental Exchange.

Level 3 includes the majority of SCE's derivatives, including over-the-counter options, bilateral contracts, capacity contracts, and QF contracts. The fair value of these derivatives is determined using

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uncorroborated non-binding broker quotes (from one or more brokers) and models which may require SCE to extrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for reasonableness.

Level 3 also includes derivatives that trade infrequently (such as firm transmission rights and CRRs in the California market, financial transmission rights traded in markets outside California and over-the-counter derivatives at illiquid locations) and long-term power agreements. For illiquid financial transmission rights and CRRs, objective criteria are reviewed, including system congestion and other underlying drivers, and fair value is adjusted when it is concluded that a change in objective criteria would result in a new valuation that better reflects fair value.

Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity and natural gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. In circumstances where Edison International cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, Edison International continues to assess valuation methodologies used to determine fair value. Derivative contracts with counterparties that have significant nonperformance risks are classified as Level 3.

In assessing nonperformance risks, Edison International reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of nonperformance. The fair value of derivative assets and derivative liabilities nonperformance risk was $4 million and $9 million, respectively, at June 30, 2010 and was $4 million and $7 million, respectively, at December 31, 2009.

The SCE nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed-income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed-income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information.

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The following tables set forth assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:

			As of June 30, 2010

(in millions)			Level 1			Level 2			Level 3			Netting and collateral ¹			Total

			(Unaudited)
Assets at Fair Value
	Money market funds ²		$	625		$	—		$	—		$	—		$	625

	Derivative contracts
		Electricity		—			142			362			(88	)		416
		Natural gas		2			1			83			(2	)		84
		Fuel oil		8			—			—			(8	)		—

		Subtotal of commodity contracts		10			143			445			(98	)		500

	Long-term disability plan			9			—			—			—			9

	Nuclear decommissioning trusts
		Stocks ³		1,635			—			—			—			1,635
		Municipal bonds		—			703			—			—			703
		Corporate bonds ⁴		—			395			—			—			395
		U.S. government and agency securities		262			54			—			—			316
		Short-term investments, primarily cash equivalents ⁵		—			12			—			—			12

		Subtotal of nuclear decommissioning trusts		1,897			1,164			—			—			3,061

Total assets ⁶			$	2,541		$	1,307		$	445		$	(98	)	$	4,195

Liabilities at Fair Value
	Derivative contracts:
		Electricity	$	—		$	(68	)	$	(1,100	)	$	70		$	(1,098	)
		Natural gas		(1	)		(234	)		(48	)		8			(275	)

		Subtotal of commodity contracts		(1	)		(302	)		(1,148	)		78			(1,373	)

		Interest rate contracts		—			(17	)		—			—			(17	)

Net assets (liabilities)			$	2,540		$	988		$	(703	)	$	(20	)	$	2,805

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			As of December 31, 2009

(in millions)			Level 1			Level 2			Level 3			Netting and Collateral ¹			Total

			(Unaudited)
Assets at Fair Value
	Money market funds ²		$	1,526		$	—		$	—		$	—		$	1,526

	Derivative contracts
		Electricity		—			235			440			(136	)		539
		Natural gas		2			10			76			(2	)		86
		Fuel oil		15			—			—			(15	)		—

		Subtotal of commodity contracts		17			245			516			(153	)		625

	Long-term disability plan			8			—			—			—			8

	Nuclear decommissioning trusts
		Stocks ³		1,772			—			—			—			1,772
		Municipal bonds		—			634			—			—			634
		Corporate bonds ⁴		—			393			—			—			393
		U.S. government and agency securities		240			68			—			—			308
		Short-term investments, primarily cash equivalents ⁵		1			14			—			—			15

		Subtotal of nuclear decommissioning trusts		2,013			1,109			—			—			3,122

Total assets ⁶			$	3,564		$	1,354		$	516		$	(153	)	$	5,281

Liabilities at Fair Value
	Derivative contracts:
		Electricity	$	—		$	(85	)	$	(433	)	$	73		$	(445	)
		Natural gas		(3	)		(150	)		(21	)		4			(170	)

		Subtotal of commodity contracts		(3	)		(235	)		(454	)		77			(615	)

		Foreign currency and interest rate contracts		—			(21	)		—			—			(21	)

Net assets (liabilities)			$	3,561		$	1,098		$	62		$	(76	)	$	4,645

¹: Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.
²: At June 30, 2010 and December 31, 2009, included in cash and cash equivalents and restricted cash and at December 31, 2009, also included in prepaid expenses and other on Edison International's consolidated balance sheets.
³: At June 30, 2010 and December 31, 2009, approximately 68% and 67% of the equity investments were located in the United States, respectively.
⁴: Corporate bonds are diversified. At June 30, 2010 and December 31, 2009, this category included $37 million and $50 million, respectively, for collateralized mortgage obligations and other asset backed securities.
⁵: Excludes net assets of $22 million and $18 million of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases at June 30, 2010 and December 31, 2009, respectively.
⁶: Excludes $32 million of cash surrender value of life insurance investments for deferred compensation at June 30, 2010 and December 31, 2009.

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The following table sets forth a summary of changes in the fair value of Level 3 assets and liabilities:

		Three Months Ended June 30,						Six Months Ended June 30,


(in millions)		2010			2009			2010			2009

		(Unaudited)
Fair value, net asset (liability) at beginning of period		$	(397	)	$	143		$	62		$	(302	)
Total realized/unrealized gains (losses):
	Included in earnings ¹		(18	)		(49	)		27			97
	Included in regulatory assets and liabilities ²		(294	)		204			(781	)		591
	Included in accumulated other comprehensive income		(2	)		—			4			—
Purchases and settlements, net			2			67			(20	)		(17	)
Transfers into or out of Level 3			6			(8	)		5			(12	)

Fair value, net asset (liability) at end of period		$	(703	)	$	357		$	(703	)	$	357

Change during the period in unrealized gains (losses) related to assets and liabilities held at the end of the period ³		$	(287	)	$	225		$	(717	)	$	675

¹: Reported in "Competitive power generation" revenue on Edison International's consolidated statements of income (loss).
²: Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.
³: Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income were $(2) million and $13 million for the three months ended June 30, 2010 and 2009, respectively, and were $32 million and $71 million for the six months ended June 30, 2010 and 2009, respectively. The remainder of the unrealized gains and losses relate to SCE. See (2) above.

There were no significant transfers between levels during the first six months of 2010. Edison International determines the fair value for transfers in and transfers out of each level as of the end of each reporting period.

Nuclear Decommissioning Trusts

SCE is collecting in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent decommissioning trusts. Contributions are approximately $46 million per year. Funds collected, together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.

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The following table sets forth amortized cost and fair value of the trust investments:

			Amortized Cost				Fair Value


(in millions)	Maturity Dates ¹		June 30, 2010		December 31, 2009		June 30, 2010		December 31, 2009

			(Unaudited)
Stocks		–	$	843	$	822	$	1,635	$	1,772
Municipal bonds		2010 – 2047		602		545		703		634
Corporate bonds		2010 – 2044		317		309		395		393
U.S. government and agency securities		2010 – 2039		285		287		316		308
Short-term investments and receivables/payables		2010		33		33		34		33

Total			$	2,080	$	1,996	$	3,083	$	3,140

¹: Maturity dates as of June 30, 2010.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Proceeds from sales of securities (which are reinvested) were $315 million and $652 million for the three months ended June 30, 2010 and 2009, respectively, and $600 million and $1.3 billion for the six months ended June 30, 2010 and 2009, respectively. Unrealized holding gains, net of losses, were $1.0 billion and $1.1 billion at June 30, 2010 and December 31, 2009, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible.

The following table sets forth a summary of changes in the fair value of the trust:

	Three Months Ended June 30,						Six Months Ended June 30,


(in millions)	2010			2009			2010			2009

	(Unaudited)
Balance at beginning of period	$	3,248		$	2,399		$	3,140		$	2,524
Realized gains		18			115			38			189
Realized losses		(5	)		(77	)		(4	)		(140	)
Unrealized gains (losses) – net		(205	)		220			(143	)		148
Other-than-temporary impairment		(7	)		(9	)		(11	)		(103	)
Interest, dividends, contributions and other		34			25			63			55

Balance at end of period	$	3,083		$	2,673		$	3,083		$	2,673

Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on operating revenue or earnings.

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Long-term Debt

The carrying amounts and fair values of long-term debt are:

	June 30, 2010				December 31, 2009


(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

	(Unaudited)
Long-term debt, including current portion	$	11,155	$	10,793	$	10,814	$	10,452

Fair values of long-term debt are based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes of new issue prices and relevant credit information.

The carrying value of trade receivables, payables and short-term debt approximate fair value and therefore are not included in the table above.

Note 11. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)	June 30, 2010		December 31, 2009


	(Unaudited)
Current:
Regulatory balancing accounts	$	194	$	94
Energy derivatives		143		25
Other		1		1

		338		120

Long-term:
Regulatory balancing accounts		43		43
Deferred income taxes – net		1,775		1,561
Unamortized nuclear investment – net		310		340
Nuclear-related ARO investment – net		248		258
Unamortized coal plant investment – net		71		73
Unamortized loss on reacquired debt		277		287
Pensions and other postretirement benefits		1,004		1,014
Energy derivatives		1,092		357
Environmental remediation		39		36
Other		199		170

		5,058		4,139

Total regulatory assets	$	5,396	$	4,259

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Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	June 30, 2010		December 31, 2009


	(Unaudited)
Current:
Regulatory balancing accounts	$	455	$	363
Other		2		4

		457		367

Long-term:
Regulatory balancing accounts		808		642
ARO		12		171
Costs of removal		2,571		2,515

		3,391		3,328

Total regulatory liabilities	$	3,848	$	3,695

Note 12. Other Income and Expenses

Other income and expenses are as follows:

	Three Months Ended June 30,				Six Months Ended June 30,


(in millions)	2010		2009		2010		2009

	(Unaudited)
Other Income:
Equity AFUDC	$	25	$	18	$	54	$	35
Increase in cash surrender value of life insurance policies		6		6		12		13
Other		4		5		4		8

Total utility other income		35		29		70		56

Competitive power generation and parent		1		1		—		2

Total other income	$	36	$	30	$	70	$	58

Other Expenses:
Civic, political and related activities and donations	$	9	$	6	$	15	$	8
Marketing services		2		6		3		6
Other		4		—		8		6

Total utility other expenses		15		12		26		20

Competitive power generation and parent		1		5		2		5

Total other expenses	$	16	$	17	$	28	$	25

Note 13. Variable Interest Entities

Effective January 1, 2010, Edison International adopted the FASB's new guidance regarding variable interest entities ("VIEs"). A VIE is defined as a legal entity whose equity owners do not have sufficient equity at risk, or, as a group, the holders of the equity investment at risk lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The new guidance replaces the predominantly quantitative

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model for determining which reporting entity, if any, has a controlling financial interest in a VIE with a qualitative approach. Under this new qualitative model, the primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE unless specific exceptions or exclusions are met. Commercial and operating activities are generally the factors that most significantly impact the economic performance of VIEs in which Edison International has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.

Projects or Entities that are Consolidated

At June 30, 2010 and December 31, 2009, EMG had majority interests in 15 wind projects with a total generating capacity of 701 MW that have minority interests held by others. The projects are located in Iowa, Minnesota, New Mexico, Nebraska and Texas. As of December 31, 2009, all of these projects were consolidated by EMG. Upon the application of the new guidance effective January 1, 2010, EMG deconsolidated two of these projects. See further discussion in "—Variable Interests in VIEs that are not Consolidated—Equity Interests." In determining that EMG was the primary beneficiary of the 13 projects consolidated at June 30, 2010, the key factors considered were EMG's ability to direct commercial and operating activities and EMG's obligation to absorb losses and right to receive benefits that could potentially be significant to the variable interest entities.

The following table presents summarized financial information of the wind projects that had minority interests held by others and were consolidated by Edison International:

(in millions)		June 30, 2010		December 31, 2009


		(Unaudited)
Current assets		$	26	$	73
Net property, plant and equipment ¹			682		944
Other long-term assets			2		2

	Total assets ¹	$	710	$	1,019

Current liabilities		$	16	$	17
Long-term obligations net of current maturities			18		20
Deferred revenues			57		58
Other long-term liabilities			19		21

	Total liabilities	$	110	$	116

Noncontrolling interests		$	5	$	76

¹: Amounts included assets of $253 million ($247 million of net property, plant and equipment) that were deconsolidated on January 1, 2010.

Assets serving as collateral for the debt obligations had a carrying value of $79 million and $81 million at June 30, 2010 and December 31, 2009, respectively, and primarily consist of property, plant and equipment.

EMG has a 50% partnership interest in the Ambit project. EMG has the power to direct the commercial and operating activities of the project pursuant to the existing contracts and has the obligation to absorb losses and right to receive benefits from the project. Therefore, under the new

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guidance, EMG is the primary beneficiary which resulted in the consolidation of the Ambit project by Edison International. Total assets consolidated at January 1, 2010 and June 30, 2010 were $99 million and $100 million, respectively. Substantially all of the assets of the Ambit project are pledged as collateral for the partnership's debt obligations.

Variable Interests in VIEs that are not Consolidated

Power Purchase Contracts

SCE has power purchase agreements ("PPAs") in which it has a variable interest in 17 VIEs, including 6 tolling agreements where SCE provides the natural gas to operate the plants and 11 contracts with QFs (including the Big 4 projects) that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. In general, because payments for capacity are the primary source of income, the most significant economic activity for SCE's VIEs is the operation and maintenance of the power plants. SCE does not have control over the operation and maintenance of the facilities considered VIEs and it does not bear operational risk of the facilities. See further discussion of the Big 4 projects below.

As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts, which are accounted for at fair value. See Note 10 for a discussion on nonperformance risk. Further, SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 6. The aggregate capacity dedicated to SCE for these VIE projects was 1,749 MW at June 30, 2010 and the amounts that SCE paid to these projects were $117 million and $115 million for the three months ended June 30, 2010 and 2009, respectively, and $242 million and $231 million for the six months ended June 30, 2010 and 2009, respectively. These amounts are recoverable in customer rates.

The following table summarizes as of June 30, 2010, SCE's assets and liabilities and exposure to loss associated with SCE's variable interests in the VIEs described above:

	Assets				Liabilities


(in millions)	Short- Term		Long- Term		Short- Term		Long- Term		Maximum Exposure

	(Unaudited)
Derivatives	$	—	$	—	$	42	$	964	$	—
Accounts payable		—		—		59		—		—

Total	$	—	$	—	$	101	$	964	$	—

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The following table summarizes as of December 31, 2009, SCE's assets and liabilities and exposure to loss associated with SCE's variable interests in the VIEs described above:

	Assets				Liabilities


(in millions)	Short- Term		Long- Term		Short- Term		Long- Term		Maximum Exposure

	(Unaudited)
Derivatives	$	—	$	43	$	17	$	385	$	43
Accounts payable		—		—		39		—		—

Total	$	—	$	43	$	56	$	385	$	43

Realized and unrealized losses are recovered or expected to be recovered from ratepayers in rates, subject to reasonableness, and therefore are not reflected in earnings.

Equity Interests

EMG accounts for domestic energy projects where EMG has a 50% or less ownership interest and cannot exercise unilateral control under the equity method. As of June 30, 2010 and December 31, 2009, EMG had significant variable interests in projects that are not consolidated consisting of the Big 4 projects and the Sunrise project. A subsidiary of EMG operates the Big 4 projects and EMG's partner provides the fuel management services. In addition, the executive director of these projects is provided by EMG's partner. Commercial and operating activities are jointly controlled by a management committee of each VIE. Accordingly, EMG continues to account for its variable interests under the equity method.

As noted previously in "Projects or Entities that are Consolidated," EMG deconsolidated two renewable wind energy generating facilities, the Elkhorn Ridge wind project and San Juan Mesa wind project, on January 1, 2010. The commercial and operating activities of these entities are directed by a management committee comprised of representatives of each partner. Thus, EMG is not the primary beneficiary of these projects. Accordingly, effective January 1, 2010, EMG accounts for its interests in these projects under the equity method.

The following table presents the carrying amount of EMG's investments in unconsolidated variable interest entities and the maximum exposure to loss for each investment as of June 30, 2010:

	June 30, 2010

(in millions)	Investment		Maximum Exposure

	(Unaudited)
Natural gas-fired projects	$	325	$	325
Wind projects		174		174

EMG's maximum exposure to loss in its variable interest entities accounted for under the equity method is generally limited to its investment in these entities. Two of EMG's domestic energy projects have long-term debt that is secured by a pledge of assets of the project entity, but does not provide for any recourse to EME. Accordingly, a default on a long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EMG's investment, but would not require EMG to contribute additional capital. At June 30, 2010, entities which EMG has accounted for under the equity method had indebtedness of $143 million, of which $54 million is proportionate to EMG's ownership interest in these projects.

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Big 4 Projects Consolidated Prior to 2010

Edison International has variable interests in the Big 4 Projects through equity interests held by EMG and power contracts between SCE and the Big 4 Projects that contain variable contract pricing provisions based on the price of natural gas. Prior to 2010, Edison International had determined that SCE was the primary beneficiary of these four VIEs and, therefore, consolidated these projects. Edison International deconsolidated the Big 4 Projects at January 1, 2010 since it did not control the commercial and operating activities of these projects through EMG and SCE. Commercial and operating activities are jointly controlled by a management committee of each VIE. Therefore, neither EMG, SCE nor Edison International on a consolidated basis has control of the entities. In addition, EMG's partner provides the executive director and fuel management services and the steam supply is based on the needs of EMG's partner. The deconsolidation did not result in a gain or loss.

The following table presents the carrying amounts of VIEs consolidated by Edison International at December 31, 2009 (these balances were deconsolidated at January 1, 2010):

(in millions)		December 31, 2009


		(Unaudited)
Cash		$	92
Other current assets			81
Competitive power generation and other property, plant and equipment—net			253
Other long-term assets			4

	Total assets	$	430

Current liabilities		$	64
Asset retirement obligations			17
Noncontrolling interest			349

	Total liabilities and equity	$	430

Note 14. Business Segments

Edison International's reportable business segments include its electric utility operation segment (SCE) and a competitive power generation segment (EMG). Prior to January 1, 2010, Edison International reported three business segments: electric utility operations segment, competitive power generation segment and financial services segment. As a result of termination of the cross-border leases during 2009 and the continued decline of the remaining portfolio of the financial services segment, the remaining business activity is no longer significant enough to report separately. Accordingly, the financial services segment has been combined into the competitive power generation segment for all periods presented. The combination of these business activities is consistent with the management structure of EMG and evaluation of performance by Edison International. The significant accounting policies of the segments are the same as those described in Note 1.

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Segment income statement information was:

	Three Months Ended June 30,						Six Months Ended June 30,


(in millions)	2010			2009			2010			2009

	(Unaudited)
Operating Revenue (Loss):
Electric utility	$	2,247		$	2,273		$	4,406		$	4,462
Competitive power generation		495			562			1,147			1,186
Parent and other ²		(1	)		(1	)		(1	)		(2	)

Consolidated Edison International	$	2,741		$	2,834		$	5,552		$	5,646

Net Income (Loss) attributable to Edison International:
Electric utility ³	$	301		$	499		$	465		$	707
Competitive power generation ^1,4		27			(558	)		104			(510	)
Parent and other ^2,5		16			43			11			37

Consolidated Edison International	$	344		$	(16	)	$	580		$	234

Segment balance sheet information was:

(in millions)	June 30, 2010			December 31, 2009


	(Unaudited)
Total Assets:
Electric utility	$	34,213		$	32,474
Competitive power generation		9,212			9,543
Parent and other ²		(370	)		(573	)

Consolidated Edison International	$	43,055		$	41,444

¹: Includes earnings (losses) from discontinued operations of $1 million and $(7) million for the three months ended June 30, 2010 and 2009, respectively, and $8 million and $(4) million for the six months ended June 30, 2010 and 2009, respectively.
²: Includes amounts from Edison International (parent) and other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.
³: Includes earnings of $53 million and $300 million for both the three- and six-month periods ended June 30, 2010 and 2009, respectively, related to the federal and state impacts of the Global Settlement. See Note 4.
⁴: Includes earnings of $58 million for both the three- and six-month periods ended June 30, 2010 and losses of $612 million and $624 million for the three- and six-month periods ended June 30, 2009, respectively, related to termination of Edison Capital's cross-border leases and the federal and state impacts of Global Settlement on EMG. See Note 4.
⁵: Includes earnings of $27 million and $50 million for both the three- and six-month periods ended June 30, 2010 and 2009, respectively, related to the federal and state impacts of the Global Settlement. See Note 4.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS

This MD&A contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Edison International's current expectations and projections about future events based on Edison International's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by Edison International that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact Edison International, include, but are not limited to:

•: environmental laws and regulations, at both state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business;
•: cost of capital and the ability to borrow funds and access the capital markets on reasonable terms;
•: cost and availability of electricity, including the ability to procure sufficient resources to meet expected customer needs in the event of significant counterparty defaults under power-purchase agreements;
•: changes in the fair value of investments and other assets;
•: ability of SCE to recover its costs in a timely manner from its customers through regulated rates;
•: decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays in regulatory actions;
•: changes in interest rates and rates of inflation, including those rates which may be adjusted by public utility regulators;
•: governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by Independent System Operators and Regional Transmission Organizations;
•: risks associated with operating nuclear and other power generating facilities, including operating risks; nuclear fuel storage issues; failure, availability, efficiency, output, cost of repairs and retrofits of equipment; and availability and cost of spare parts;
•: availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;
•: cost and availability of labor, equipment and materials;

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•: ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance;
•: ability to recover uninsured losses in connection with wildfire-related liability;
•: effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
•: potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;
•: outcome of disputes with state tax authorities regarding tax positions taken by Edison International;
•: cost and availability of coal, natural gas, fuel oil, and nuclear fuel, and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;
•: cost and availability of emission credits or allowances for emission credits;
•: transmission congestion in and to each market area and the resulting differences in prices between delivery points;
•: ability to provide sufficient collateral in support of hedging activities and power and fuel purchased;
•: weather conditions, natural disasters and other unforeseen events;
•: risks inherent in the development of generation projects and transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, construction, permitting, and governmental approvals; and
•: risks that competing transmission systems will be built by merchant transmission providers in SCE's territory.

Additional information about risks and uncertainties, including more detail about the factors described above, are discussed throughout this MD&A and in the "Risk Factors" section included in Part I, Item 1A of the 2009 Form 10-K. Readers are urged to read this entire report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect Edison International's business. Forward-looking statements speak only as of the date they are made and Edison International is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International with the Securities and Exchange Commission.

This MD&A for the three- and six-month periods ended June 30, 2010 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2009, and as compared to the three-and six-month periods ended June 30, 2009. This discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2009 (the "year-ended 2009 MD&A"), which was included in the 2009 Form 10-K.

Except when otherwise stated, references to each of Edison International, SCE and EMG mean each such company with its subsidiaries on a consolidated basis. References to "Edison International (parent)" or "parent company" mean Edison International on a stand-alone basis, not consolidated with its subsidiaries.

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EDISON INTERNATIONAL OVERVIEW

Introduction

This overview is presented in six sections:

•: Highlights of operating results,
•: SCE capital program,
•: SCE 2012 General Rate Case,
•: Environmental developments,
•: EMG's renewables programs, and
•: Parent company liquidity.

The overview is presented as an update to the overview presented in the 2009 Form 10-K. See pages 62 to 69 of the 2009 Form 10-K for additional information on these topics.

Highlights of Operating Results

			Three Months Ended June 30,									Six Months Ended June 30,

			2010			2009			Change			2010			2009			Change

Net Income attributable to Edison International
	SCE		$	301		$	499		$	(198	)	$	465		$	707		$	(242	)
	EMG			27			(558	)		585			104			(510	)		614
	Edison International Parent and Other			16			43			(27	)		11			37			(26	)

	Edison International Consolidated			344			(16	)		360			580			234			346

Non-Core Earnings (Loss)
	Global Settlement ¹ :
		SCE		53			300			(247	)		53			300			(247	)
		EMG ²		58			(612	)		670			58			(624	)		682
		Edison International Parent and Other		27			50			(23	)		27			50			(23	)
	SCE – tax impact of health care legislation			—			—			—			(39	)		—			(39	)
	EMG discontinued operations			1			(7	)		8			8			(4	)		12

	Edison International Consolidated			139			(269	)		408			107			(278	)		385

Core Earnings (Loss)
	SCE			248			199			49			451			407			44
	EMG			(32	)		61			(93	)		38			118			(80	)
	Edison International Parent and Other			(11	)		(7	)		(4	)		(16	)		(13	)		(3	)

	Edison International Consolidated		$	205		$	253		$	(48	)	$	473		$	512		$	(39	)

¹: Includes the impact of state taxes related to issues resolved as part of the Global Settlement.
²: Includes the impact of termination of two of Edison Capital's cross-border leases.

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Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings by principal operating subsidiary internally for financial planning and for analysis of performance. Core earnings by principal operating subsidiary are also used when communicating with analysts and investors regarding our earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to Edison International shareholders excluding income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: settlement of prior year tax liabilities and change in tax law; exit activities, including lease terminations, asset impairments, sale of certain assets, early debt extinguishment costs and other activities that are no longer continuing; and non-recurring regulatory or legal proceedings.

SCE's 2010 core earnings increased $49 million and $44 million for the quarter and year-to-date, respectively. The quarter increase was due to lower income tax expense and higher authorized revenue to support rate base growth. These quarter increases were partially offset by higher operating expenses, including the impact of curtailed spending last year due to the timing of the 2009 CPUC GRC decision. The year-to-date increase was due to higher authorized revenue to support rate base growth, lower income tax expense and higher capitalized financing costs (AFUDC). These year-to-date increases were partially offset by higher operating expenses, including the impact of curtailed spending last year due to the timing of the 2009 CPUC GRC decision. The lower tax expense for the quarter and year-to-date includes a change in method of tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program.

EMG's 2010 core earnings decreased $93 million and $80 million for the quarter and year-to-date, respectively. The decline in core earnings during the second quarter reflects increased coal fleet maintenance activities for scheduled plant outages, impact of unrealized gains and losses and lower generation. In addition, second quarter of 2009 results included $20 million after tax related to the sale of an interest in the Midlands Cogeneration Ventures leverage lease. In addition to the decrease in earnings attributable to the leverage lease transaction, the decrease in the six month results includes the higher scheduled outages during the second quarter, impact of unrealized gains and losses, and lower average realized energy prices. Partially offsetting these decreases in the six month results were higher trading revenues and distributions from two projects recorded in the first quarter.

Consolidated non-core items for Edison International included:

•: An earnings benefit of $138 million recorded in the second quarter of 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002 (described in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K) and revision to interest recorded on the federal Global Settlement. Edison International is awaiting receipt of final interest calculations from the California Franchise Tax Board.
•: A non-cash charge of $39 million in the first quarter of 2010 to reverse previously recognized federal tax benefits eliminated by the federal health care legislation. The Patient Protection and Affordable Care Act, as modified by the Health Care and Education Reconciliation Act, was enacted in March 2010. The new health care legislation includes a provision that eliminates the federal tax deduction of retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies. Although this change does not take effect until January 1, 2013, Edison International is required to recognize the full accounting impact of the legislation in its financial statements in the period of enactment.

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•: An after-tax earnings charge of $262 million and $274 million for the three- and six-month periods ended June 30, 2009, respectively, related to the Global Settlement with the IRS and termination of Edison Capital's cross-border leases ($920 million pre-tax loss).

SCE Capital Program

SCE's capital program continues to be focused primarily in five areas:

•: Upgrading and constructing new transmission lines to strengthen system reliability and increase access to renewable energy, including the Tehachapi, Devers-Colorado River and Eldorado-Ivanpah projects.
•: Maintaining reliability and expanding capability of SCE's transmission and distribution system.
•: Developing and installing up to 250 MW of utility-owned solar photovoltaic generating facilities (generally ranging in size from 1 to 2 MW each) on commercial and industrial rooftops and other space in SCE's service territory.
•: Replacing steam generators at San Onofre intended to enable operations until at least the end of its initial license period in 2022. During the first quarter of 2010, SCE completed the replacement of the steam generators at San Onofre Unit 2, which was returned to service on April 11, 2010. See "SCE: Results of Operations—Electric Utility Results of Operations—Utility Earning Activities" for discussion of the extended outage at San Onofre Unit 2.
•: Installing "smart" meters in approximately 5.3 million households and small businesses referred to as EdisonSmartConnect™. During the first six months of 2010, SCE installed approximately 860,000 smart meters, with cumulative installations totaling over 1 million.

SCE continues to plan to utilize cash generated from its operations and issuance of additional debt and preferred equity for its capital program. During the six months ended June 30, 2010, SCE issued long-term debt (see "SCE: Liquidity and Capital Resources—Historical Consolidated Cash Flow—Condensed Consolidated Statement of Cash Flows—Cash Flows Provided (Used) by Financing Activities" for further information).

SCE's capital investments (including accruals) during the six months ended June 30, 2010 totaled $1.5 billion. SCE projects that capital investments will be in the range of $3.3 billion to $4.0 billion in 2010 and the 2010 – 2014 total capital investment spending will be in the range of $18 billion to $21.5 billion. The rate of actual capital spending will be affected by permitting, regulatory, market and other factors as discussed further under "SCE: Liquidity and Capital Resources—Capital Investment Plans" in the 2009 Form 10-K.

SCE 2012 General Rate Case

On July 19, 2010, SCE submitted to the CPUC's Division of Ratepayer Advocates its notice of intent (NOI) to file a 2012 GRC. The NOI indicates that SCE's GRC application, expected to be filed by year-end 2010, will request a 2012 base rate revenue requirement of $6.3 billion. After considering the effects of sales growth, SCE's request would be a $903 million increase over projected 2011 base rate revenue. If the CPUC approves the requested rate increase and allocates the increase to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 16.9% and 7.9%, respectively. The requested revenue requirement increase is driven by the need to maintain system reliability, accommodate customer load growth, and

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increase operation and maintenance expenses primarily for capital-related projects, information technology, insurance and pension contributions. The NOI also indicates that SCE's application will propose a post-test year ratemaking mechanism which would result in 2013 and 2014 incremental base revenue requirement increases, net of sales growth, of $305 million and $542 million, respectively, for the same reasons. The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted.

Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

Environmental Regulation Developments

Greenhouse Gas Regulation Developments

In June 2010, the US EPA published its final greenhouse gas tailoring rule, with less stringent statutory emissions thresholds for greenhouse gases than those originally proposed in late 2009. Since the rule

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affects only new or modified sources, it is not expected to have any immediate effect on the fossil-fuel generating stations of SCE or EMG.

Transport Rule and Coal Combustion Waste Regulation

In June and July of 2010, two proposed rules were published. The first proposed rule, known as the Transport Rule (a replacement for the CAIR), would substantially reduce power plant emissions of NO _x and SO ₂ starting in 2012, with additional reductions in 2014, and would impose new limitations on emissions allowance trading. The second proposal relates to the handling of coal combustion wastes.

California Renewable Energy Developments

In June 2010, CARB released a proposed Renewable Electricity Standard regulation, which would require most retail sellers of electricity in California to procure 33% of their electricity from eligible renewable energy resources by 2020. The California legislature is also contemplating legislation to adopt a 33% renewables portfolio standard that may supersede the CARB regulation and impose its own program structure. SCE believes that achieving a 33% renewables portfolio standard in this timeframe will be highly ambitious, given the magnitude of the infrastructure build-out required and the slow pace of transmission permitting and approvals.

Once-Through Cooling

On May 4, 2010, the California State Water Resources Board issued a final policy, which establishes closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like San Onofre and many of the existing fossil-fueled power plants along the California coast. The final policy requires an independent engineering study to be conducted regarding the feasibility of compliance by California's two coastal nuclear power plants. Depending on the results of the study, the required compliance may result in significant capital expenditures at San Onofre and may affect its operations. It may also significantly impact SCE's ability to procure generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems, system reliability and the cost of electricity to the extent other coastal power plants in California are forced to shut down or limit operations.

For further description discussion, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Environmental Developments."

EMG Renewable Program

EMG has four projects totaling 600 MW under construction. Included among the projects under construction is the 130 MW Taloga project, which is slated to utilize wind turbines that are subject to a legal dispute. EMG also had a development pipeline of potential wind projects with projected installed capacity of approximately 3,400 MW at June 30, 2010. EMG had a purchase contract for 69 MW of wind turbines, and 33 MW of wind turbines in storage, that are to be used for projects not yet under construction as of June 30, 2010, excluding turbine purchase contracts for 199 MW of wind turbines that are subject to a legal dispute. EMG has deferred delivery and payment for the 69 MW of turbines under the purchase contract to January 2011. If EMG is unable to develop such projects on acceptable terms and conditions, certain turbine orders may be terminated, which would result in a material charge. The pace of additional growth in EMG's renewables program will be subject to the availability of projects that meet EMG's requirements and the capital needed for development, which will be affected by the extent of internally generated cash flow and future decisions about capital expenditures for environmental compliance by its coal fleet. Consequently, pending substantial progress on or

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financing of the environmental retrofits, growth of the renewables program may depend upon the availability of third-party financing.

Mitsubishi Lawsuit

EME filed a complaint in the Superior Court of the State of California against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. Matters under dispute include, among other things, the requirement to purchase and pay the remaining purchase price for 199 MW of wind turbines, including related services and warranties, among other items, in the approximate amount of $289 million. The complaint asks the Court for, among other things, an order finding the supply agreement void and unenforceable and for an award of monetary damages, including return to EME of deposits of $68 million previously made for the units subject to dispute. See "Legal Proceedings" in Part II of this quarterly report.

Parent Company Liquidity

The parent company's liquidity and its ability to pay operating expenses and dividends to common shareholders have historically been dependent on dividends from SCE, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capital markets. Given its subsidiaries' plans to use their cash flows for their respective capital needs, Edison International (parent) expects to incur additional borrowings to fund its dividends to common shareholders and operating expenses.

At June 30, 2010, Edison International (parent) had approximately $27 million of cash and equivalents. The following table summarizes the status of the Edison International (parent) credit facility at June 30, 2010:

(in millions)	Edison International (parent)


Commitment	$	1,426
Outstanding borrowings		(215	)
Outstanding letters of credit		—

Amount available	$	1,211

Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1. At June 30, 2010, Edison International's consolidated debt to total capitalization ratio was 0.53 to 1.

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SOUTHERN CALIFORNIA EDISON COMPANY

RESULTS OF OPERATIONS

SCE's results of operations are derived mainly through two sources:

•: Utility earning activities, which mainly represent CPUC- and FERC-authorized base rates, which allow a reasonable return, and CPUC-authorized incentive mechanisms; and
•: Utility cost-recovery activities, which mainly represent CPUC-authorized balancing accounts, which allow recovery of costs (including carrying costs) incurred or provide mechanisms to track and recover or refund differences in forecasted and actual amounts. Balancing accounts (except for certain capital-related projects) do not allow for a return.

Utility earning activities include base rates that are designed to recover forecasted operation and maintenance costs, certain capital-related carrying costs, interest, taxes and a return, including the return and taxes on capital projects recovered through balancing account mechanisms. Differences between authorized and actual results impact earnings. Also included in utility earning activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.

Utility cost-recovery activities include rates which provide for recovery, subject to reasonableness review, of fuel costs, purchased power costs, certain operation and maintenance expenses (including public purpose related program costs), and depreciation expense related to certain projects. There is no return earned on cost-recovery expenses.

Electric Utility Results of Operations

The following table is a summary of SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities.

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Three Months Ended June 30, 2010 versus June 30, 2009

		Three Months Ended June 30, 2010								Three Months Ended June 30, 2009


(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities ^1,2		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities ^1,2			Total Consolidated

Operating revenue		$	1,308		$	939	$	2,247		$	1, 253		$	1,020		$	2,273

Fuel and purchased power			—			706		706			—			739			739
Operation and maintenance			537			218		755			516			246			762
Depreciation, decommissioning and amortization			306			14		320			275			14			289
Property and other taxes			61			1		62			61			—			61
Gain on sale of assets			—			—		—			—			(1	)		(1	)

Total operating expenses			904			939		1,843			852			998			1,850

Operating income			404			—		404			401			22			423
Net interest expense and other			(85	)		—		(85	)		(87	)		—			(87	)

Income before income taxes			319			—		319			314			22			336
Income tax expense (benefit)			5			—		5			(198	)		—			(198	)

Net income			314			—		314			512			22			534
Net income attributable to noncontrolling interests			—			—		—			—			22			22
Dividends on preferred and preference stock not subject to mandatory redemption			13			—		13			13			—			13

Net income available for common stock		$	301		$	—	$	301		$	499		$	—		$	499

Core Earnings ³							$	248								$	199
Non-Core Earnings:
	Global Settlement							53									300
	Tax impact of health care legislation							—									—

Total SCE GAAP Earnings							$	301								$	499

¹: Effective January 1, 2010, SCE deconsolidated the Big 4 projects which affects comparability of cost-recovery activities (see "Edison International Notes to Consolidated Financial Statements Note 13. Variable Interest Entities" for further discussion). Included in the three- and six-month periods ended June 30, 2009, respectively, were the following balances related to the Big 4 projects:

(in millions)	Three Months Ended June 30, 2009		Six Months Ended June 30, 2009


Operating revenue	$	131	$	274

Fuel		76		177
Operation and maintenance		25		46
Depreciation		8		17

Total operating expenses		109		240

Net income	$	22	$	34

²: Effective July 1, 2009, SCE transferred Mountainview Power Company, LLC, to SCE (see "Note 8. Property and Plant" in the 2009 Form 10-K for further discussion). As a result of the transfer and for comparability purposes, Mountainview's 2009 activities ($27 million for both operating revenue and total expenses for the three months ended June 30, 2009 and $49 million for both operating revenue and total expenses for the six months ended June 30, 2009) were reclassified from cost-recovery activities to utility earnings activities consistent with the 2010 regulatory recovery mechanism.
³: See use of Non-GAAP financial measure in "Edison International Overview—Highlights of Operating Results."

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Utility Earning Activities

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $55 million primarily due to the following:

•: $40 million increase related to implementation of the 2009 GRC (effective January 1, 2009) which authorized a 4.25% increase in 2010 authorized revenue.
•: $15 million increase related to revenue requirements for capital projects recovered through CPUC-authorized balancing accounts primarily related to the steam generator replacement project and the EdisonSmartConnect ^TM project.
•: $5 million increase related to the 2009 and 2010 FERC rate cases effective March 1, 2009 and March 1, 2010, respectively (see "SCE: Liquidity and Capital Resources—Regulatory Proceedings—2010 FERC Rate Case" for further discussion).

•

Higher operation and maintenance expense of $21 million including the impact of curtailed spending last year due to the timing of the 2009 GRC decision. The increase in operation and maintenance expense was primarily in the following areas:

•: $15 million of higher transmission and distribution expenses. In addition to the impact of curtailed spending, the 2010 increase reflects higher costs to support system reliability and infrastructure replacement, increases in preventive maintenance work and training costs.
•: $10 million of higher expenses related to higher general liability insurance, a nuclear insurance refund received in 2009, and higher injury and damage claims.

Partially offset by:

•: $10 million of lower generation expenses primarily related to a $15 million hydrogen energy project payment made in the second quarter of 2009, which was subsequently approved for balancing account treatment in December 2009.

•: Higher depreciation expense of $31 million primarily resulting from increased capital investments including capitalized software costs.

See "—Income Taxes" below for discussion of lower income taxes during the three months ended June 30, 2010 compared to the same period in 2009.

Utility Cost-Recovery Activities

Excluding the impact of deconsolidation of the Big 4 projects (see "Edison International Notes to Consolidated Financial Statements Note 13. Variable Interest Entities"), utility cost-recovery activities were primarily affected by:

•: Higher purchased power expense of $29 million primarily due to: higher QF purchased power expense of $120 million primarily due to higher natural gas prices and higher kWh purchases. This was partially offset by lower bilateral energy purchase expense of $30 million primarily due to decreased kWh purchases. Realized losses on economic hedging activities were $38 million in 2010

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and $96 million in 2009. Changes in realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than contract prices.

•: Higher fuel expense of $14 million primarily due to higher costs at Mountainview of $15 million resulting from higher natural gas prices.

Six Months Ended June 30, 2010 versus June 30, 2009

		Six Months Ended June 30, 2010									Six Months Ended June 30, 2009


(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities ^1,2			Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities ^1,2			Total Consolidated

Operating revenue		$	2,573		$	1,833		$	4,406		$	2,457		$	2,005		$	4,462

Fuel and purchased power			—			1,395			1,395			—			1,480			1,480
Operation and maintenance			1,057			411			1,468			958			462			1,420
Depreciation, decommissioning and amortization			605			24			629			548			26			574
Property and other taxes			129			1			130			127			—			127
Gain on sale of assets			—			—			—			—			(1	)		(1	)

Total operating expenses			1,791			1,831			3,622			1,633			1,967			3,600

Operating income			782			2			784			824			38			862
Net interest expense and other			(157	)		(2	)		(159	)		(169	)		(4	)		(173	)

Income before income taxes			625			—			625			655			34			689
Income tax expense (benefit)			134			—			134			(77	)		—			(77	)

Net income			491			—			491			732			34			766
Net income attributable to noncontrolling interests			—			—			—			—			34			34
Dividends on preferred and preference stock not subject to mandatory redemption			26			—			26			25			—			25

Net income available for common stock		$	465		$	—		$	465		$	707		$	—		$	707

Core Earnings ³								$	451								$	407
Non-Core Earnings:
	Global Settlement								53									300
	Tax impact of health care legislation								(39	)								—

Total SCE GAAP Earnings								$	465								$	707

¹: See footnote 1 under "—Three Months Ended June 30, 2010 versus June 30, 2009" table above.
²: See footnote 2 under "—Three Months Ended June 30, 2010 versus June 30, 2009" table above.
³: See use of Non-GAAP financial measure in "Edison International Overview—Highlights of Operating Results."

Utility Earning Activities

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $116 million primarily due to the following:

•: $80 million increase related to implementation of the 2009 GRC (effective January 1, 2009) which authorized a 4.25% increase in 2010 authorized revenue.

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•: $30 million increase related to the 2009 and 2010 FERC rate cases effective March 1, 2009 and March 1, 2010, respectively (see "SCE: Liquidity and Capital Resources—Regulatory Proceedings—2010 FERC Rate Case" for further discussion).
•: $15 million increase related to revenue requirements for capital projects recovered through CPUC-authorized balancing accounts primarily related to the steam generator replacement project and the EdisonSmartConnect ^TM project.

•

Higher operation and maintenance expense of $99 million including the impact of curtailed spending last year due to the timing of the 2009 GRC decision. The increase in operation and maintenance expense was primarily in the following areas:

•

$45 million of higher transmission and distribution expenses. In addition to the impact of curtailed spending, the 2010 increase reflects higher costs to support system reliability and infrastructure replacement, increases in preventive maintenance work, line clearing costs and training costs.

•

$30 million of higher expenses related to higher general liability insurance, a nuclear insurance refund received in 2009, and higher injury and damage claims.

•

$5 million of higher 2010 generation expenses reflecting $10 million primarily due to additional work identified during the San Onofre Unit 2 scheduled outage and $10 million primarily due to overhaul and outage costs at Four Corners. These increases were partially offset by a $15 million hydrogen energy project payment made in the second quarter of 2009, which was subsequently approved for balancing account treatment in December 2009. During the San Onofre Unit 2 scheduled outage, SCE identified and completed additional work unrelated to the steam generator replacement that resulted in increased operation and maintenance expense and extended the outage beyond SCE's initial estimated timeframe. San Onofre Unit 2 was returned to service on April 11, 2010.

The first two of the four replacement steam generators were installed in San Onofre Unit 2 in the first quarter of 2010 and the installation of the final two steam generators at San Onofre Unit 3 is expected to begin in late 2010. The CPUC has previously adopted a mechanism establishing thresholds for recovery of SCE's incurred costs for the steam generator replacements. Costs above an established threshold will require a reasonableness review. No cost recovery will be allowed for costs incurred that exceed an authorized cap. The determination of whether a reasonableness review of costs is necessary will be made after the steam generator replacement project is completed.

As discussed in the 2009 Form 10-K, SCE is subject to the jurisdiction of the NRC with respect to its San Onofre and Palo Verde Nuclear Generating Stations. San Onofre is currently addressing a number of regulatory and performance issues, and the NRC has required SCE to take actions to provide greater assurance of compliance by San Onofre personnel with applicable NRC requirements and procedures. SCE continues to implement plans to address the identified issues. The NRC has continued to affirm that San Onofre has been operated and is being operated safely; however, a number of these issues remain outstanding, and additional issues have been identified. The cumulative impact of these regulatory and performance issues has been an increase in management focus and other resources applied at San Onofre. To the extent that these issues persist, the likelihood of further required action, and associated potential for effects on costs and operations, will increase.

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•: Higher depreciation expense of $57 million primarily related to increased capital investments including capitalized software costs.
•: Lower net interest expense and other of $12 million primarily related to higher capitalized cost of equity and debt (AFUDC) resulting from a higher capitalization rate and level of construction in progress. See "Edison International Notes to Consolidated Financial Statements Note 12. Other Income and Expenses" for further detail of other income and expenses.

See "—Income Taxes" below for discussion of lower income taxes during the six months ended June 30, 2010 compared to the same period in 2009.

Utility Cost-Recovery Activities

•: Higher purchased power expense of $96 million primarily related to: higher QF purchased power expense of $250 million primarily due to higher natural gas prices and higher kWh purchases; and higher ISO-related energy costs of $75 million, including replacement power costs related to the San Onofre Unit 2 scheduled outage. This was partially offset by lower bilateral energy purchase expense of $90 million primarily due to decreased kWh purchases. Realized losses on economic hedging activities were $62 million in 2010 and $194 million in 2009. Changes in realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than contract prices.
•: Lower fuel expense of $4 million primarily related to lower costs at Four Corners (coal) of $10 million and lower costs at San Onofre Unit 2 of $5 million both resulting from the outages described above. These decreases were offset by higher costs at Mountainview of $15 million resulting from higher natural gas prices.

Supplemental Operating Revenue Information

SCE's total consolidated operating revenue was $2.2 billion and $2.3 billion for the three months ended June 30, 2010 and 2009, respectively, of which $2.4 billion and $2.3 billion was related to retail billed and unbilled revenue (excluding wholesale sales and balancing account (over)/undercollections) for the same respective periods. SCE's total consolidated operating revenue was $4.4 billion and $4.5 billion for the six months ended June 30, 2010 and 2009, respectively, of which $4.4 billion and $4.2 billion was related to retail billed and unbilled revenue (excluding wholesale sales and balancing account (over)/undercollections) for the same respective periods. Retail billed and unbilled revenue increased $57 million and $201 million for the three- and six-month periods ended June 30, 2010, respectively, compared to the same periods in 2009. The quarter and year-to-date increases reflect a rate increase of $126 million and $305 million, respectively, and a sales volume decrease of $69 million and $104 million, respectively. The rate increase was due to higher system average rates for 2010 compared to the same periods in 2009 mainly due to the implementation of the 2009 CPUC GRC decision and approved FERC transmission rate changes. The sales volume decrease was due to slightly milder weather experienced during the second quarter of 2010 compared to the same period in 2009 and economic conditions. As a result of the CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk related to electricity sales (see "Overview of Ratemaking Mechanisms" in the 2009 Form 10-K).

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Due to warmer weather during the summer months and SCE's rate design, operating revenue during the third quarter of each year is generally higher than other quarters.

Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, CDWR bond-related costs and a portion of direct access exit fees are remitted to the CDWR and are not recognized as revenue by SCE. The amounts collected and remitted to CDWR were $286 million and $582 million for the three- and six-month periods ended June 30, 2010, respectively, and $391 million and $896 million for the three- and six-month periods ended June 30, 2009, respectively. Effective January 1, 2010, the CDWR-related rates were decreased primarily to refund CDWR overcollections to customers.

Income Taxes

SCE's income tax expense from continuing operations increased $203 million and $211 million during the three- and six-month periods ended June 30, 2010, respectively. The 2010 income tax expense reflects: a $39 million non-cash charge recorded in the first quarter related to the federal health care legislation enacted in March 2010; a $40 million earnings benefit due to a change in method of tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program; and a $53 million earnings benefit recorded in the second quarter resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002. During the second quarter of 2009, SCE recognized a $300 million earnings benefit related to the federal Global Settlement finalized with the IRS. See "Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" for further discussion.

LIQUIDITY AND CAPITAL RESOURCES

SCE expects to fund its continuing obligations and projected capital investments for 2010 through cash and equivalents on hand, operating cash flows and incremental capital market financings of debt and preferred equity. SCE also has availability under its credit facilities if additional funding and liquidity are necessary to meet operating and capital requirements.

Available Liquidity

As of June 30, 2010, SCE had approximately $91 million of cash and equivalents and short-term investments. As of June 30, 2010, SCE's long-term debt, including current maturities of long-term debt, was $7.1 billion.

The following table summarizes the status of SCE's credit facilities at June 30, 2010:

(in millions)	Credit Facilities ¹


Commitment	$	2,894
Outstanding borrowings		(215	)
Outstanding letters of credit		(11	)

Amount available	$	2,668

¹: SCE has two revolving credit facilities with various banks; a $2.4 billion five-year credit facility that terminates in February 2013, with four one-year options to extend by mutual consent, and a $500 million three-year credit facility that terminates in March 2013.

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Debt Covenant

SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At June 30, 2010, SCE's debt to total capitalization ratio was 0.46 to 1.

Regulatory Proceedings

Energy Efficiency Risk/Reward Incentive Mechanism

As discussed in the year-ended 2009 MD&A, the CPUC adopted an Energy Efficiency Risk/Reward Incentive Mechanism applicable to the 2006 – 2008 performance period under which SCE expected to receive a $27 million final payment in late 2010. SCE expects a CPUC decision on the final payment, if any, in the second half of 2010. There is no assurance that SCE will receive a final payment.

2010 FERC Rate Case

Dividend Restrictions

The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted-average basis. At June 30, 2010, SCE's 13-month weighted-average common equity component of total capitalization was 51% resulting in the capacity to pay $461 million in additional dividends.

SCE paid dividends of $100 million to its parent, Edison International, in January 2010. Future dividend amounts and timing of distributions are dependent upon several factors, including the actual level of capital investments, operating cash flows and earnings.

Margin and Collateral Deposits

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. The table below illustrates the amount of collateral posted by SCE to its counterparties, as well as the potential collateral that would be required if SCE's credit rating fell below investment grade.

(in millions)	June 30, 2010


Collateral posted as of June 30, 2010 ¹	$	22
Incremental collateral requirements resulting from a potential downgrade of SCE's credit rating to below investment grade		180

Total posted and potential collateral requirements ²	$	202

¹: Collateral posted consisted of $8 million which was offset against net derivative liabilities and $14 million provided to counterparties and other brokers (consisting of $4 million in cash reflected in "Margin and collateral deposits" on the consolidated balance sheets and $10 million in letters of credit).
²: Total posted and potential collateral requirements may increase by an additional $13 million, based on SCE's forward position as of June 30, 2010, due to adverse market price movements over the remaining life of the existing contracts using a 95% confidence level.

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Historical Consolidated Cash Flow

This section discusses consolidated cash flows from operating, financing and investing activities.

Condensed Consolidated Statement of Cash Flows

	Six Months Ended June 30,

(in millions)	2010			2009

Cash flows provided by operating activities	$	1,095		$	2,054
Cash flows provided (used) by financing activities		465			(1,694	)
Cash flows used by investing activities		(1,937	)		(1,517	)

Net decrease in cash and equivalents	$	(377	)	$	(1,157	)

Cash Flows Provided by Operating Activities

Cash provided by operating activities decreased $959 million in the second quarter of 2010, compared to the second quarter of 2009 primarily due to the impacts of the Global Settlement, which resulted in a net tax allocation payment received in 2009 from Edison International of $875 million and an increase in deferred tax liabilities related to the settlement of affirmative claims. The 2010 change was also due to the timing of cash receipts and disbursements related to working capital items and a decrease in pre-tax income.

Cash Flows Provided (Used) by Financing Activities

Financing activities for the first six months of 2010 were as follows:

•: Reissued $144 million of tax-exempt pollution control bonds due in 2035. The proceeds from these bonds were used to repay commercial paper borrowings and for general corporate purposes.
•: Issued $500 million of first refunding mortgage bonds due in 2040. The bond proceeds were used to repay commercial paper borrowings and for general corporate purposes.
•: Issued $215 million of short-term debt to fund interim working capital requirements.
•: Repaid $250 million of senior unsecured notes.
•: Paid $100 million in dividends to Edison International.

Financing activities for the first six months of 2009 were as follows:

•: Issued $500 million of first refunding mortgage bonds due in 2039 and $250 million of first and refunding mortgage bonds due in 2014. The bond proceeds were used for general corporate purposes and to finance fuel inventories.
•: Repaid a net $1.9 billion of short-term debt.
•: Repaid $150 million of first and refunding mortgage bonds.

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•: Purchased $219 million of two issues of tax-exempt pollution control bonds and converted the issues to a variable rate structure. As discussed above, SCE reissued $144 million of these bonds during the first six months of 2010. SCE continues to hold the remaining $75 million of these bonds which are outstanding and have not been retired or cancelled.
•: Paid $100 million in dividends to Edison International.

Cash Flows Used by Investing Activities

Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Cash paid for capital expenditures was $1.8 billion and $1.4 billion for the six months ended June 30, 2010 and 2009, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $97 million and $105 million for the six months ended June 30, 2010 and 2009, respectively.

Contractual Obligations and Contingencies

Contractual Obligations

For a discussion of issuances of long-term debt, see "Edison International Notes to Consolidated Financial Statements Note 3. Liabilities and Lines of Credit—Long-Term Debt."

For a discussion of purchase obligations and capital lease obligations, see "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Commitments and —Other Commitments."

Contingencies

Developments related to SCE's FERC Transmission Incentives and CWIP Proceedings, Navajo Nation Litigation and Spent Nuclear Fuel are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies."

Environmental Remediation

As of June 30, 2010, SCE identified 23 sites for remediation and recorded an estimated minimum liability of $38 million. SCE expects to recover 90% of its remediation costs at certain sites. SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $3 million to $18 million. See "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies" for further discussion.

MARKET RISK EXPOSURES

For a detailed discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "SCE: Market Risk Exposures—Commodity Price Risk" in the year-ended 2009 MD&A.

Interest Rate Risk

At June 30, 2010, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $8.1 billion, compared to a carrying value of $7.1 billion. At June 30, 2010, SCE

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did not believe that its short-term debt was subject to interest rate risk due to the fair value being approximately equal to the carrying value.

Commodity Price Risk

Natural Gas and Electricity Price Risk

The following table summarizes the fair values of outstanding derivative instruments used at SCE to mitigate its exposure to spot market prices. For further discussion on fair value measurements, see "Edison International Notes to Consolidated Financial Statements Note 10. Fair Value Measurements."

	June 30, 2010					December 31, 2009


(in millions)	Assets		Liabilities			Assets		Liabilities

Electricity options, swaps and forward arrangements	$	1	$	89		$	1	$	25
Natural gas options, swaps and forward arrangements		84		280			86		171
Congestion revenue rights		190		—			217		—
Tolling arrangements ¹		—		1,006			43		402
Netting and collateral		—		(8	)		—		—

Total	$	275	$	1,367		$	347	$	598

¹: In compliance with a CPUC mandate, SCE held an open, competitive solicitation that produced agreements with different project developers who have agreed to construct new southern California generating resources. The contracts provide for fixed capacity payments as well as pricing for energy delivered based on a heat rate and contractual operation and maintenance prices. However, due to uncertainty regarding the availability of required emission credits, some of the generating resources may not be constructed and the contracts associated with these resources could therefore terminate, at which time SCE would no longer account for these contracts as derivatives.

The change in the fair value of derivative contracts for the six months ended June 30, 2010 was as follows:

(in millions)


Fair value of derivative contracts, net liability at January 1, 2010		$	(251	)
Total realized/unrealized net losses:
	Included in regulatory assets and liabilities ¹		(919	)
Purchases and settlements, net			70
Netting and collateral			8

Fair value of derivative contracts, net liability at June 30, 2010		$	(1,092	)

¹: Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.

SCE recognizes realized gains and losses on derivative instruments as purchased power expense and recovers these costs, subject to reasonableness, from ratepayers. As a result, realized gains and losses are not reflected in earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are recorded as regulatory assets or liabilities and therefore are not reflected in earnings. Realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than contract prices. Unrealized losses on economic hedging activities were primarily due to lower forward heat rates (spread between electricity prices and natural gas prices) related to SCE's long-term contracts from new natural gas-fired generation facilities.

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Credit Risk

Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. As of June 30, 2010, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:

	June 30, 2010

(in millions)	Exposure ²		Collateral		Net Exposure

S&P Credit Rating ¹
A or higher	$	217	$	—	$	217
A-		—		—		—
BBB+		1		—		1
BBB		—		—		—
BBB-		—		—		—
Below investment grade and not rated		—		—		—

Total	$	218	$	—	$	218

¹: SCE assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.
²: Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheets, except for any related net accounts receivable.

The credit risk exposure set forth in the above table is comprised of less than $1 million of net account receivables and $218 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

The CAISO comprises 87% of the total net exposure above and is mainly related to the CRRs' fair value (see "—Commodity Price Risk" for further information).

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EDISON MISSION GROUP

RESULTS OF OPERATIONS

The following table is a summary of EMG's results of operations. Effective January 1, 2010, Edison International combined the competitive power generation and financial services segments into one business segment. The change resulted from termination of cross-border leases during 2009 and the continued decline of the remaining portfolio of the financial services segment. Accordingly, the financial services segment has been combined retroactively for all periods presented into one business segment. The combination of these business activities is consistent with the management structure of EMG and evaluation of performance by Edison International.

Results of Continuing Operations

This section discusses operating results for the three- and six-month periods ended June 30, 2010 and 2009. EMG's continuing operations include the fossil-fueled facilities, renewable energy and gas-fired projects, energy trading, and gas-fired projects under contract, corporate interest expense and general and administrative expenses. EMG's discontinued operations include all international operations, except the Doga project.

The following table is a summary of competitive power generation results of operations for the periods indicated.

		Three Months Ended June 30,						Six Months Ended June 30,


(in millions)		2010			2009			2010			2009

Competitive power generation operating revenue		$	495		$	562		$	1,147		$	1,186

Fuel			160			172			374			359
Other operation and maintenance			319			244			570			483
Depreciation, decommissioning and amortization			60			58			120			114
Lease terminations and other			—			867			3			889

Total operating expenses			539			1,341			1,067			1,845
Operating income (loss)			(44	)		(779	)		80			(659	)

Interest and dividend income			4			14			24			21
Equity in income from partnerships and unconsolidated subsidiaries – net			20			17			39			15
Other income			1			1			—			2
Interest expense – net of amounts capitalized			(66	)		(75	)		(133	)		(152	)
Other expenses			—			(5	)		—			(4	)

Income (loss) from continuing operations before income taxes			(85	)		(827	)		10			(777	)

Income tax expense (benefit)			(111	)		(275	)		(86	)		(270	)
Income (loss) from continuing operations			26			(552	)		96			(507	)
Income (loss) from discontinued operations – net of tax			1			(7	)		8			(4	)

Net income (loss)			27			(559	)		104			(511	)
Less: Net income (loss) attributable to noncontrolling interests			—			(1	)		—			(1	)

Net income (loss) available for common stock		$	27		$	(558	)	$	104		$	(510	)

Core Earnings (Loss) ¹		$	(32	)	$	61		$	38		$	118
Non-Core Earnings (Loss):
	Global Settlement ²		58			(612	)		58			(624	)
	Discontinued Operations		1			(7	)		8			(4	)

Total EMG GAAP Earnings (Loss)		$	27		$	(558	)	$	104		$	(510	)

¹: See use of Non-GAAP financial measure in "Edison International Overview—Highlights of Operating Results."
²: Includes the impact of termination of two of Edison Capital's cross-border leases and impact of state taxes related to issues resolved as part of the Global Settlement.

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EMG's second quarter 2010 core earnings were lower than second quarter 2009 core earnings primarily due to the following:

•: $160 million decreased income from Midwest Generation and Homer City due to lower realized energy revenue and higher plant maintenance costs primarily attributed to scheduled plant outages during 2010. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the second quarter. Lower availability in 2010 compared to the same period in 2009 was also the result of deratings caused by opacity at the Homer City facilities and transmission line tornado damage impacting the Powerton Station. In addition, EMG's results were impacted by $17 million of unrealized losses during the second quarter of 2010 compared to unrealized gains of $24 million during the same period last year.
•: $33 million gain in the second quarter of 2009 from the sale of an interest in a leverage lease (Midlands Cogeneration Ventures) and lower lease income from termination of cross-border leverage leases in 2009.

These decreases were partially offset by the following:

•: $14 million increased energy trading revenue during the second quarter of 2010 due to congestion and basis trading.
•: $9 million decrease in corporate expenses due primarily to lower renewable energy development expenses.

EMG's core earnings for the six months ended June 30, 2010 were lower than core earnings for the six months ended June 30, 2009 primarily due to the following:

•: $186 million decreased income from Midwest Generation and Homer City due to lower realized energy revenue and higher plant maintenance costs primarily attributed to scheduled plant outages during 2010. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the first half of the year. Lower availability in 2010 compared to the same period in 2009 was also the result of deratings caused by opacity at the Homer City facilities and transmission line tornado damage impacting the Powerton Station. In addition, EMG's results were impacted by $17 million of unrealized losses during the six months ended June 30, 2010 compared to unrealized gains of $39 million during the same period last year.
•: $33 million gain in the second quarter of 2009 from the sale of an interest in a leverage lease (Midlands Cogeneration Ventures) and lower lease income from termination of cross-border leverage leases in 2009.

These decreases were partially offset by the following:

•: $51 million increased energy trading revenue due to congestion and basis trading.
•: $9 million decrease in corporate expenses due primarily to lower renewable energy development expenses.

Consolidated non-core items for EMG included:

•: An earnings benefit of approximately $58 million recorded in the second quarter of 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002 and revision to interest recorded on the federal Global Settlement.

Adjusted Operating Income ("AOI") – Overview

The following section and table provide a summary of results of EMG's operating projects and corporate expenses for the second quarters of 2010 and 2009 and six months ended June 30, 2010 and 2009, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

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The following table shows the adjusted operating income (AOI) of EMG's projects:

	Three Months Ended June 30,						Six Months Ended June 30,


(in millions)	2010			2009			2010			2009

Midwest Generation plants	$	(39	)	$	74		$	48		$	188
Homer City facilities		—			47			37			83
Renewable energy projects		19			11			29			37
Energy trading		31			17			78			27
Big 4 projects		12			11			16			17
Sunrise		7			6			3			1
Doga		—			8			15			8
March Point		—			1			17			3
Westside projects		—			—			1			3
Leveraged lease income		1			1			2			12
Lease termination and other		—			(867	)		(3	)		(889	)
Other projects		3			3			6			5
Other operating income (expense)		2			(4	)		4			(10	)

		36			(692	)		253			(515	)
Corporate administrative and general		(36	)		(47	)		(74	)		(84	)
Corporate depreciation and amortization		(4	)		(4	)		(8	)		(7	)

AOI ¹	$	(4	)	$	(743	)	$	171		$	(606	)

¹: AOI is equal to operating income under GAAP, plus equity in earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net (income) loss attributable to noncontrolling interests in AOI is meaningful for investors as these components are integral to the operating results of EMG.

The following table reconciles AOI to operating income (loss) as reflected on EMG's consolidated statements of income (loss):

		Three Months Ended June 30,						Six Months Ended June 30,


(in millions)		2010			2009			2010		2009

AOI		$	(4	)	$	(743	)	$	171	$	(606	)
Less:
	Equity in earnings (losses) of unconsolidated affiliates		20			17			39		15
	Dividend income from projects		2			8			18		10
	Production tax credits		19			14			33		30
	Other income, net		(1	)		(3	)		1		(2	)

Operating Income (Loss)		$	(44	)	$	(779	)	$	80	$	(659	)

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Adjusted Operating Income from Consolidated Operations

Midwest Generation Plants

The following table presents additional data for the Midwest Generation plants:

			Three Months Ended June 30,					Six Months Ended June 30,


(in millions)			2010			2009		2010		2009

Operating Revenues			$	281		$	340	$	660	$	724
Operating Expenses
	Fuel ¹			98			110		239		233
	Plant operations			169			106		268		202
	Plant operating leases			18			19		37		38
	Depreciation and amortization			28			27		56		54
	Administrative and general			7			5		12		10

	Total operating expenses			320			267		612		537

Operating Income (Loss)				(39	)		73		48		187

Other Income				—			1		—		1

AOI			$	(39	)	$	74	$	48	$	188

Statistics
	Generation (in GWh):
		Energy only contracts		5,430			6,361		13,642		12,117
		Load requirements services contract		—			447		—		1,333

	Total			5,430			6,808		13,642		13,450

¹: Included in fuel costs were $1 million and $14 million during the second quarters of 2010 and 2009, respectively, and $5 million and $33 million during the six months ended June 30, 2010 and 2009, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of NO _X emission allowances to Midwest Generation were $0.4 million and $1 million during the six months ended June 30, 2010 and 2009, respectively. Transfers of SO ₂ emission allowances from Midwest Generation were $5 million during the first six months of 2010. For more information regarding the price of emission allowances, see "EMG: Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

AOI from the Midwest Generation plants decreased $113 million and $140 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 decreases in AOI were primarily attributable to an increase in plant operations costs related to scheduled plant outages, unrealized losses related to hedge contracts and a decline in realized gross margin. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the second quarter. The decline in realized gross margin during the second quarter was driven by lower generation, partially offset by higher capacity revenues. The year-to-date decline in realized gross margin was driven by lower average realized energy prices, partially offset by higher capacity revenues.

Included in operating revenues were unrealized gains (losses) of $(3) million and $5 million for the second quarters of 2010 and 2009, respectively, and $4 million and $20 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 were due to both the

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ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges, and hedge contracts which are not accounted for as cash flow hedges (referred to as economic hedges). Unrealized gains in 2009 were primarily due to economic hedge contracts that are accounted for on a mark-to-market basis.

Included in fuel expenses were unrealized gains (losses) of $(2) million and $14 million for the second quarters of 2010 and 2009, respectively, and $(7) million and $14 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) were due to oil futures contracts, which were accounted for as economic hedges. The contracts hedge a portion of a fuel adjustment mechanism of a rail transportation contract.

For more information regarding forward market prices and unrealized gains (losses), see "EMG: Market Risk Exposures—Commodity Price Risk" and "EMG: Results of Operations—Derivative Instruments," respectively.

Homer City Facilities

The following table presents additional data for the Homer City facilities:

		Three Months Ended June 30,				Six Months Ended June 30,


(in millions)		2010		2009		2010		2009

Operating Revenues		$	129	$	161	$	304	$	326
Operating Expenses
	Fuel ¹		57		63		127		127
	Plant operations		39		22		76		56
	Plant operating leases		27		25		52		50
	Depreciation and amortization		4		3		9		8
	Administrative and general		2		1		3		2

	Total operating expenses		129		114		267		243

Operating Income			—		47		37		83

AOI		$	—	$	47	$	37	$	83

Statistics
	Generation (in GWh)		2,289		3,025		5,243		5,683

¹: Included in fuel costs were $1 million during each of the second quarters of 2010 and 2009, and $5 million and $8 million during the six months ended June 30, 2010 and 2009, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of SO ₂ emission allowances to Homer City were $5 million during the six months ended June 30, 2010. Transfers of NO _x emission allowances from Homer City were $0.4 million and $1 million during the six months ended June 30, 2010 and 2009, respectively. For more information regarding the price of emission allowances, see "EMG: Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

AOI from the Homer City facilities decreased $47 million and $46 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 decreases in AOI were primarily attributable to an increase in plant operations costs related to scheduled plant outages, higher unrealized losses related to hedge contracts and a decline in realized gross margin. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the

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second quarter. The decline in realized gross margin was driven by lower generation and higher coal costs, partially offset by higher capacity revenues.

Included in operating revenues were unrealized gains (losses) from hedge activities of $(12) million and $5 million for the second quarters of 2010 and 2009, respectively, and $(14) million and $5 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 and 2009 were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at Homer City was attributable to changes in the difference between energy prices at the PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). For more information regarding forward market prices and unrealized gains (losses), see "EMG: Market Risk Exposures—Commodity Price Risk" and "EMG: Results of Operations—Derivative Instruments."

Non-GAAP Disclosures—Fossil-Fueled Facilities

Adjusted Operating Income

AOI is equal to operating income (loss) plus other income (expense) for the fossil-fueled facilities. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of other income (expense) is meaningful for investors as the components of other income (expense) are integral to the operating results of the fossil-fueled facilities.

Seasonal Disclosure—Fossil-Fueled Facilities

Due to fluctuations in electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the fossil-fueled facilities normally vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall), further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, AOI from the fossil-fueled facilities is seasonal and has significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. For further discussion regarding market prices, see "EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities."

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Renewable Energy Projects

The following table presents additional data for EMG's renewable energy projects:

		Three Months Ended June 30,				Six Months Ended June 30,


(in millions)		2010		2009		2010		2009

Operating Revenues		$	34	$	31	$	64	$	75
Production Tax Credits			19		14		33		30

			53		45		97		105

Operating Expenses
	Plant operations		12		12		24		25
	Depreciation and amortization		22		21		43		41
	Administrative and general		—		1		1		2

	Total operating expenses		34		34		68		68

AOI ¹		$	19	$	11	$	29	$	37

Statistics
	Generation (in GWh) ²		992		718		1,835		1,538

¹: AOI is equal to operating income (loss) plus equity in earnings (losses) of unconsolidated affiliates, production tax credits, other income and expense, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based upon a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Under GAAP, production tax credits generated by wind projects are recorded as a reduction in income taxes. Accordingly, AOI represents a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in AOI for wind projects is meaningful for investors as federal and state subsidies are an integral part of the economics of these projects. The following table reconciles AOI as shown above to operating income (loss) under GAAP:

		Three Months Ended June 30,					Six Months Ended June 30,


(in millions)		2010		2009			2010			2009

AOI		$	19	$	11		$	29		$	37
Less:
	Production tax credits		19		14			33			30

Operating Income (Loss)		$	—	$	(3	)	$	(4	)	$	7

²: Includes renewable energy projects that are unconsolidated at EMG. Generation excluding unconsolidated projects was 821 GWh and 1,512 GWh for the three months and six months ended June 30, 2010, respectively.

AOI from renewable energy projects increased $8 million and decreased $8 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The second quarter increase in AOI was primarily attributable to higher generation resulting from an increase in projects in operations. The year-to-date decrease in AOI results from higher depreciation and operations costs related to additional projects in operations, offset by the impact of the deconsolidation of two renewable projects in 2010. AOI in the second quarter and six months ended June 30, 2009 included $5 million and $16 million, respectively, of liquidated damages from availability guarantees provided by a wind turbine supplier, which compensated EMG for lower generation (none recorded in 2010). The second quarter ended June 30, 2010 did not include liquidated damages for equipment warranty related items given completion of the blade remediation

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program. During the second quarter of 2010, EMG received $92 million in U.S. Treasury grants, which was recorded as deferred revenue and is recognized as revenue over the life of the project.

Energy Trading

EMG seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, coal, and transmission congestion primarily in the eastern U.S. power grid using products available over the counter, through exchanges, and from ISOs.

AOI from energy trading activities increased $14 million and $51 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 increases in AOI from energy trading activities were attributable to increased revenue in congestion and basis trading.

Adjusted Operating Income from Leveraged Lease Activities

AOI from leveraged lease income decreased by $10 million for the six months ended June 30, 2010, compared to the corresponding period of 2009 due to the termination of the cross-border leases and the sale of a lease investment during the first half of 2009.

Adjusted Operating Income from Lease Termination and Other

AOI from lease termination and other included losses of $889 million for the six months ended June 30, 2009 due to the termination of the cross-border leases. (See "Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K, for further information.

Adjusted Operating Income from Unconsolidated Affiliates

Doga

AOI from the Doga project decreased $8 million and increased $7 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009 due to the timing of distributions. AOI is recognized when cash is distributed from the project since the Doga project is accounted for on the cost method.

March Point

AOI from the March Point project increased $14 million for the six months ended June 30, 2010, compared to the corresponding period of 2009. The 2010 increase was primarily due to an $18 million equity distribution received from the project in February 2010. EMG subsequently sold its ownership interest in the March Point project to its partner at book value.

Seasonal Disclosure

EMG's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.

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Interest Related Income (Expense)

			Three Months Ended June 30,						Six Months Ended June 30,


(in millions)			2010			2009			2010			2009

Interest income			$	3		$	5		$	6		$	11

Interest expense:
	EME debt		$	(58	)	$	(68	)	$	(118	)	$	(136	)
	Non-recourse debt:
		Midwest Generation		—			(2	)		(1	)		(5	)
		EME Funding		—			(2	)		—			(4	)
		EME CP Holding Co.		(1	)		(1	)		(2	)		(2	)
		Viento Funding II, Inc.		(4	)		—			(8	)		—
		Other projects		(3	)		(2	)		(4	)		(5	)

			$	(66	)	$	(75	)	$	(133	)	$	(152	)

The 2010 decrease in interest expense was primarily due to higher capitalized interest and lower debt balances under EME's and Midwest Generation's credit facilities. Capitalized interest for projects under construction increased $8 million and $13 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The year-to-date variance was also due to the repayment of debt at EME Funding related to the Big 4 projects.

Income Taxes

EMG's income taxes from continuing operations during the second quarter of 2010 included a $58 million income tax benefit resulting from acceptance by the California Franchise Tax of the tax positions finalized with the IRS as part of the Global Settlement for tax years 1986 through 2002. In addition, the income taxes for the six months ended June 30, 2010 and 2009, included tax benefits of production and housing tax credits of $34 million during each period. During the second quarter of 2009, an income tax benefit was recorded on a pre-tax loss on termination of leverage leases at Edison Capital and impact of the federal Global Settlement finalized with the IRS.

Results of Discontinued Operations

Income from discontinued operations, net of tax, increased $8 million and $12 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 increase was due to lower foreign exchange rates. The year-to-date increase was due to a reduction in EMG's estimated liability due primarily to expiration of a contract indemnity during the first quarter of 2010. EMG increased its estimated liability for a tax indemnity by $6 million in the second quarter and six months ended June 30, 2009.

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Derivative Instruments

Unrealized Gains and Losses

EMG classifies unrealized gains and losses from derivative instruments (other than the effective portion of derivatives that qualify for hedge accounting) as part of operating revenues or fuel expenses. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities:

		Three Months Ended June 30,					Six Months Ended June 30,

(in millions)		2010			2009		2010			2009

Midwest Generation plants
	Non-qualifying hedges	$	(4	)	$	18	$	(6	)	$	34
	Ineffective portion of cash flow hedges		(1	)		1		3			—
Homer City facilities
	Non-qualifying hedges		—			1		—			—
	Ineffective portion of cash flow hedges		(12	)		4		(14	)		5

Total unrealized gains (losses)		$	(17	)	$	24	$	(17	)	$	39

At June 30, 2010, cumulative unrealized gains of $25 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($16 million for the remainder of 2010, $8 million for 2011, and $1 million for 2012).

Fair Value Disclosures

In determining the fair value of EMG's derivative positions, EMG uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EMG's derivative instruments, see "Edison International Notes to Consolidated Financial Statements—Note 10. Fair Value Measurements" and "—Note 2. Derivative Instruments and Hedging Activities," respectively, and refer to "EMG: Results of Operations—Fair Value of Derivative Instruments" in the year-ended 2009 MD&A.

LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

At June 30, 2010, EMG and its subsidiaries had consolidated cash and cash equivalents of $746 million and a total of $961 million of capacity under its credit facilities. EMG's consolidated debt at June 30, 2010 was $4.1 billion, of which $107 million was current. In addition, EMG's subsidiaries had $3.0 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 25 years.

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The following table summarizes the status of the EME and Midwest Generation credit facilities at June 30, 2010:

(in millions)	EME			Midwest Generation


Commitment	$	600		$	500
Less: Commitment from Lehman Brothers subsidiary		(36	)		—

		564			500
Outstanding borrowings		—			—
Outstanding letters of credit		(100	)		(3	)

Amount available	$	464		$	497

As a result of credit ratings actions in 2010, described under "—Credit Ratings," the margins applicable to Midwest Generation's $500 million working capital facility increased 27.5 basis points. Borrowings made under this credit facility currently bear interest at LIBOR plus 1.15%, unless average utilized commitments during a period exceed $250 million, in which case the margin increases to 1.275%.

For the remainder of 2010, EMG anticipates capital expenditures of $635 million (excluding a $289 million disputed amount under a turbine supply agreement) to be funded with a combination of project-level financing, U.S. Treasury grants, cash on hand, and cash flow from operations. EMG secured a $206 million vendor financing, of which $200 million was available at June 30, 2010, and a $160 million project financing, of which $70 million was available at June 30, 2010. EMG intends to file for U.S. Treasury grants for its renewable energy projects in construction.

EMG may from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, EMG's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

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Capital Investment Plan

At June 30, 2010, forecasted capital expenditures through 2012 by EMG's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

(in millions)		July through December 2010		2011		2012


Midwest Generation Plants
	Plant capital expenditures	$	26	$	79	$	10
	Environmental expenditures ¹		93		145		78
Homer City Facilities
	Plant capital expenditures		8		52		24
	Environmental expenditures ²		1		3		22
Renewable Projects
	Capital and construction expenditures ³		495		—		—
	Turbine commitments ⁴		—		85		—
Other capital expenditures			12		17		9

Total		$	635	$	381	$	143

¹: Environmental expenditures include primarily expenditures related to SNCR equipment and $156 million for expenditures during the remainder of 2010 to 2012 to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO ₂ emissions. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply remain subject to conditions applicable at the time decisions are required or made. For additional discussion, see "Edison International Overview—Environmental Developments" and refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K.
²: Excludes amounts that may become required under environmental regulations for future operations. For further information, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Environmental Developments—Transport Rule" and "—Contingencies—Homer City New Source Review Notice of Violation.
³: Includes projects under construction where project financing has been secured. The available balance under secured financing arrangements was $270 million as of June 30, 2010. For further discussion, see "Edison International Notes to Consolidated Financial Statements—Note 3. Liabilities and Lines of Credit," and refer to "EMG: Liquidity and Capital Resources Project-Level Financing" in the year-ended 2009 MD&A.
⁴: Turbine commitment figures exclude $289 million which is subject to dispute under provisions in one of the turbine supply agreements. In March 2010, EME filed a breach of contract complaint against this turbine supplier. For additional discussion, see "Legal Proceedings" in Part II of this quarterly report.

Estimated Expenditures for Existing Projects

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, mill steam inerting projects, generator stator rewinds, 4Kv switchgear and main power transformer replacement.

Environmental expenditures at Homer City relate to emission monitoring and control projects. Midwest Generation is subject to various commitments with respect to environmental compliance. Expenditures, in addition to those included on the preceding table, are anticipated and could be material; however,

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the amounts and timing have not been determined. For more information on the current status of environmental improvements in Illinois, see "Edison International Overview—Environmental Developments." For further discussion of environmental regulations, refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K.

Estimated Expenditures for Future Projects

EMG has wind turbines in storage and on order for wind projects under construction and to be used for future wind projects (turbine commitments are reflected separately in the preceding capital expenditure table). Amounts exclude balance of project costs for 102 MW available for new projects, which EMG estimates to be an additional $75 million to $120 million based on typical project costs. The pace of additional growth in EMG's renewables program will be subject to the availability of projects that meet EMG's requirements and the capital needed for development, which will be affected by the extent of internally generated cash flow and future decisions about capital expenditures for environmental compliance by its coal fleet. Consequently, pending substantial progress on or financing of the environmental retrofits, growth of the renewables programs may depend upon the availability of outside project-level debt and equity financing. Successful completion of the development of a wind project depends upon obtaining permits and agreements necessary to support an investment and may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment.

Historical Consolidated Cash Flow

This section discusses EMG's consolidated cash flows from operating, financing and investing activities.

Condensed Consolidated Statement of Cash Flows

	Six Months Ended June 30,

(in millions)	2010			2009

Operating cash flows used by continuing operations	$	(120	)	$	(1,139	)
Operating cash flow from discontinued operations		8			(4	)

Net cash used by operating activities		(112	)		(1,143	)
Net cash provided (used) by financing activities		(52	)		147
Net cash provided (used) by investing activities		(274	)		1,233

Net increase (decrease) in cash and cash equivalents	$	(438	)	$	237

Cash Flows Used by Operating Activities

Cash used by operating activities from continuing operations decreased $1 billion in the first six months of 2010, compared to the first six months of 2009. The 2009 change was primarily due to the impacts of the Global Settlement which resulted in remittances of net tax allocation payments to Edison International of $1.1 billion by Edison Capital related to the termination of Edison Capital's interests in cross-border leases (see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K for further discussion). In April 2010, Edison Capital funded a $253 million deposit to the IRS related to the Global Settlement. The 2010 change was also due to a decrease in cash collateral deposits for risk management and energy trading compared to 2009, $92 million received related to U.S. Treasury grants, and changes in the timing of cash receipts and disbursements related to working capital items.

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Cash Flows Provided (Used) by Financing Activities

Cash provided (used) by financing activities from continuing operations decreased $199 million in the first six months of 2010, compared to the first six months of 2009. The 2010 decrease was primarily attributable to lower levels of renewable energy project financing. For further project financing details, see "Edison International Notes to Consolidated Financial Statements—Note 3. Liabilities and Lines of Credit." In addition, in January 2010, Edison Capital redeemed in full its medium-term loans.

Cash Flows Provided (Used) by Investing Activities

Cash provided (used) by investing activities from continuing operations decreased $1.5 billion in the first six months of 2010, compared to the first six months of 2009. The 2010 decrease was primarily due to $1.385 billion of net proceeds from termination of the cross-border leases at Edison Capital in 2009. The change was also due to higher expenditures for construction of renewable energy projects compared to 2009.

Credit Ratings

Overview

On June 29, 2010, Moody's lowered the credit ratings of EME to B3 from B2 and Midwest Generation to Ba2 from Ba1. EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

EMG does not have any "rating triggers" contained in subsidiary financings that would result in it being required to make equity contributions or provide additional financial support to its subsidiaries, including EMMT. However, coal contracts at Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. For discussions of contingent features related to energy contracts, see "—Margin, Collateral Deposits and Other Credit Support for Energy Contracts."

Credit Rating of EMMT

For a discussion of the effect of EMMT's credit rating on EMG's ability to sell forward the output of the Homer City facilities through EMMT, refer to "EMG: Liquidity and Capital Resources—Credit Ratings—Credit Rating of EMMT" in the year-ended 2009 MD&A.

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

Future cash collateral requirements may be higher than the margin and collateral requirements were at June 30, 2010, if wholesale energy prices change or if EMMT enters into additional transactions. EMG estimates that margin and collateral requirements for energy and congestion contracts outstanding as of June 30, 2010 could increase by approximately $184 million over the remaining life of the contracts using a 95% confidence level. This increase may not be offset by similar changes in the cash flows of the underlying hedged items in the same periods. Certain EMMT hedge contracts do not require margin, but contain provisions that require EMG or Midwest Generation to comply with the terms and

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conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—Debt Covenants and Dividend Restrictions."

Hedge contracts include provisions relating to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. EMMT has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at June 30, 2010 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or additional collateral postings under the contingent features described above.

Midwest Generation has cash on hand and a credit facility to support margin requirements specifically related to contracts entered into by EMMT related to the Midwest Generation plants. In addition, EMG has cash on hand and a credit facility to provide credit support to subsidiaries. For discussion on available borrowing capacity under Midwest Generation and EME credit facilities, see "—Available Liquidity."

Debt Covenants and Dividend Restrictions

Credit Facility and Financial Ratios

EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-capital ratio as such terms are defined in the credit facility.

The following table sets forth the interest coverage ratio:

	12 Months Ended

(in millions)	June 30, 2010		December 31, 2009

Ratio		1.72		1.72
Covenant threshold (not less than)		1.20		1.20

The following table sets forth the corporate-debt-to-capital ratio:

(in millions)


Corporate-debt-to-capital ratio	0.53	0.54
Covenant threshold (not more than)	0.75	0.75

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Dividend Restrictions in Major Financings

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at June 30, 2010 or for the 12 months ended June 30, 2010:

Subsidiary	Financial Ratio	Covenant	Actual


Midwest Generation (Midwest Generation plants)	Debt to Capitalization Ratio	Less than or equal to 0.60 to 1	0.16 to 1
Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.53 to 1

For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "EMG: Liquidity and Capital Resources—Debt Covenants and Dividend Restrictions—Dividend Restrictions in Major Financings" in the year-ended 2009 MD&A.

EME's Senior Notes and Guaranty of Powerton-Joliet Leases

EME is restricted under applicable agreements from the sale or disposition of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding the sale or disposition in question. At June 30, 2010, the maximum permissible sale or disposition of EME assets was $805 million.

Contractual Obligations and Contingencies

Fuel Supply and Transportation Contracts

For a discussion of fuel supply contracts and coal transportation agreements, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Other Commitments."

Midwest Generation New Source Review Lawsuit

For a discussion of the Midwest Generation New Source Review Lawsuit, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Lawsuit."

Homer City New Source Review Notice of Violation

For a discussion of the Homer City New Source Review Notice of Violation, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Homer City New Source Review Notice of Violation."

Off-Balance Sheet Transactions

For a discussion of Edison International's off-balance sheet transactions, refer to "EMG: Liquidity and Capital Resources—Off-Balance Sheet Transactions" in the year-ended 2009 MD&A. There have been

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no significant developments with respect to Edison International's off-balance sheet transactions that affect disclosures presented in the 2009 Form 10-K.

Environmental Matters and Regulations

For a discussion of EMG's environmental matters, refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K. There have been no significant developments with respect to environmental matters specifically affecting EMG since the filing of the 2009 Form 10-K, except as set forth in "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Environmental Developments."

MARKET RISK EXPOSURES

For a detailed discussion of EMG's market risk exposures, including commodity price risk, credit risk and interest rate risk, refer to "EMG: Market Risk Exposures" in the year-ended 2009 MD&A.

Commodity Price Risk

Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities

Energy and capacity from the fossil-fueled facilities are sold under terms, including price, duration and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Power is sold into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to generation are generally entered into at the Northern Illinois Hub or the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City facilities. These trading hubs have been the most liquid locations for hedging purposes.

The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first six months of 2010 and 2009:

		24-Hour Average Historical Market Prices ¹

		2010		2009

Midwest Generation plants
	Northern Illinois Hub	$	33.44	$	30.08
Homer City facilities
	PJM West Hub	$	43.88	$	41.40
	Homer City Busbar		38.28		38.01

¹: Energy prices were calculated at the respective delivery points using historical hourly real-time prices as published by PJM or provided on the PJM web site.

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The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at June 30, 2010:

		24-Hour Forward Energy Prices ¹

		Northern Illinois Hub		PJM West Hub

2010
	July	$	40.32	$	53.39
	August		39.34		52.04
	September		31.05		42.66
	October		26.59		40.15
	November		30.05		41.16
	December		32.43		44.25
2011 calendar "strip" ²		$	32.75	$	45.54

¹: Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub and PJM West Hub delivery points.
²: Market price for energy purchases for the entire calendar year.

Forward market prices at the Northern Illinois Hub and PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth, and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the fossil-fueled facilities into these markets may vary materially from the forward market prices set forth in the preceding table.

EMMT engages in hedging activities for the fossil-fueled facilities to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load-serving transactions and forward contracts accounted for on the accrual basis) as of June 30, 2010 for electricity expected to be generated during the remainder of 2010 and in 2011 and 2012:

		2010				2011				2012


		MWh (in thousands)		Average price/ MWh ¹		MWh (in thousands)		Average price/ MWh ¹		MWh (in thousands)		Average price/ MWh ¹

Midwest Generation plants
	Northern Illinois and AEP/Dayton Hubs		9,835	$	42.87		14,152	$	37.93		2,040	$	41.37
Homer City facilities ²
	PJM West Hub		2,540		71.19		2,428		52.15		1,182		51.78

Total			12,375				16,580				3,222

¹: The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions are not directly comparable to the 24-hour Northern Illinois Hub or PJM West Hub prices set forth above.
²: Includes hedging transactions primarily at the PJM West Hub and to a lesser extent at other trading locations. Years 2010, 2011 and 2012 include hedging activities entered into by EMMT for the Homer City facilities that are not designated under the intercompany agreements with Homer City due to limitations under the sale leaseback transaction documents.

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In addition, as of June 30, 2010, EMMT had entered into 1.5 bcf of natural gas futures contracts (equivalent to approximately 255 GWh of energy only contracts using a ratio of 6 MMBtu to 1 MWh) for the Midwest Generation plants to economically hedge energy price risks during 2010 at an equivalent average energy price of approximately $38.40/MWh.

Capacity Price Risk

The following table summarizes the status of capacity sales for Midwest Generation and Homer City at June 30, 2010:

									RPM Capacity Sold in Base Residual Auction				Other Capacity Sales, Net of Purchases ²


		Installed Capacity MW		Unsold Capacity ¹ MW			Capacity Sold MW		MW		Price per MW-day		MW			Average Price per MW-day		Aggregate Average Price per MW-day

July 1, 2010 to May 31, 2011
	Midwest Generation		5,477		(548	)		4,929		4,929	$	174.29		—		$	—	$	174.29
	Homer City		1,884		(211	)		1,673		1,813		174.29		(140	)		55.36		184.24
June 1, 2011 to May 31, 2012
	Midwest Generation		5,477		(495	)		4,982		4,582		110.00		400			85.00		107.99
	Homer City		1,884		(113	)		1,771		1,771		110.00		—			—		110.00
June 1, 2012 to May 31, 2013
	Midwest Generation		5,477		(773	)		4,704		4,704		16.46		—			—		16.46
	Homer City		1,884		(148	)		1,736		1,736		133.37		—			—		133.37
June 1, 2013 to May 31, 2014
	Midwest Generation		5,477		(827	)		4,650		4,650		27.73		—			—		27.73
	Homer City		1,884		(104	)		1,780		1,780		226.15		—			—		221.03	³

¹: Capacity not sold arises from: (i) capacity retained to meet forced outages under the RPM auction guidelines, and (ii) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.
²: Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.
³: Includes the impact of a 100 MW capacity swap transactions executed prior to the base residual auction at $135 MW-day.

The RPM auction capacity prices for the delivery period of June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the price of $27.73 per MW-day was substantially lower than other areas' capacity prices. The impact of lower capacity prices for this period compared to previous years will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by an unavailability of competing resources and increased energy prices, which is uncertain.

Basis Risk

During the six months ended June 30, 2010, transmission congestion in PJM has resulted in prices at the individual busbars of the Midwest Generation plants being lower than those at the AEP/Dayton Hub and Northern Illinois Hub by an average of 11% and 1%, respectively, compared to 17% and less

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than 1%, respectively, during the six months ended June 30, 2009. During the six months ended June 30, 2010 and 2009, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 13% and 8%, respectively.

Coal and Transportation Price Risk

The Midwest Generation plants and Homer City facilities purchase coal primarily from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at June 30, 2010 for the remainder of 2010 and the following three years:

	Amount of Coal Under Contract in Millions of Equivalent Tons ¹

	July through December 2010		2011		2012		2013

Midwest Generation plants ²		10.2		11.7		9.8		—
Homer City facilities		2.5		4.2		1.7		0.5

¹: The amount of coal under contract in tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Midwest Generation plants and 13,000 Btu equivalent for the Homer City facilities.
²: In July 2010, Midwest Generation entered into additional contracts for the purchase of 3.9 million tons of coal for 2011.

EMG is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which are related to the price of coal purchased for the Homer City facilities, increased during 2010 from 2009 year-end prices. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO ₂ per MMBtu sulfur content) increased to a price of $62.75 per ton at July 2, 2010, compared to a price of $52.50 per ton at December 31, 2009, as reported by the Energy Information Administration.

Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO ₂ per MMBtu sulfur content) purchased for the Midwest Generation plants increased during 2010 from 2009 year-end prices. The market price of PRB coal increased to a price of $13.05 per ton at July 2, 2010, compared to a price of $9.25 per ton at December 31, 2009, as reported by the Energy Information Administration.

EMG has contracts for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various short-haul carriers), which extends through 2011. EMG is exposed to price risk related to transportation rates after the expiration of its existing transportation contracts. Current market transportation rates for PRB coal are higher than the existing rates under contract. Transportation costs are approximately half of the delivered cost of PRB coal to the Midwest Generation plants.

Emission Allowances Price Risk

EMG purchases (or sells) emission allowances for the fossil-fueled facilities based on the amounts required for actual generation in excess of (or less than) the amounts allocated to these facilities under applicable programs. In the event that actual emission allowances required are greater than allowances held, EMG is subject to price risk for purchases of emission allowances. The market price for emission allowances may vary significantly. The average purchase price of SO ₂ allowances decreased to $50 per

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ton during the six months ended June 30, 2010 from $65 per ton in 2009. The average purchase price of annual NO _x allowances decreased to $974 per ton during the six months ended June 30, 2010 from $1,431 per ton in 2009. Based on broker's quotes and information from public sources, the spot price for SO ₂ allowances and annual NO _x allowances was $15 per ton and $465 per ton, respectively, at June 30, 2010.

For a discussion of environmental regulations related to emissions, refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K.

Credit Risk

The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EMG's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At June 30, 2010, the balance sheet exposure as described above, broken down by the credit ratings of EMG's counterparties, was as follows:

		June 30, 2010

(in millions)		Exposure ²		Collateral			Net Exposure

Credit Rating ¹
	A or higher	$	133	$	(28	)	$	105
	A-		120		(6	)		114
	BBB+		27		—			27
	BBB		23		—			23
	BBB-		23		—			23
	Below investment grade		20		(18	)		2

Total		$	346	$	(52	)	$	294

¹: EMG assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.
²: Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheets, except for any related accounts receivable.

The credit risk exposure set forth in the above table is comprised of $139 million of net accounts receivable and payables and $207 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Due to developments in the financial markets, credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EMG's subsidiaries have posted a $108 million cash margin in the aggregate with PJM, New York Independent System Operator (NYISO), Midwest Independent Transmission System Operator (MISO), clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EMG to credit risk of the related entities.

The fossil-fueled facilities sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 67% of EMG's consolidated operating revenues for the six months ended June 30, 2010. PJM, a regional transmission organization (RTO) with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade

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companies. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At June 30, 2010, EMG's account receivable due from PJM was $66 million.

The terms of EMG's wind turbine supply agreements contain significant obligations of the suppliers in the form of manufacturing and delivery of turbines, and payments for delays in delivery and for failure to meet performance obligations and warranty agreements. EMG's reliance on these contractual provisions is subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to EMG's turbine suppliers may have a material impact on EMG's wind projects and development efforts.

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EMG mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. For details, see "Edison International Notes to Consolidated Financial Statements—Note 3. Liabilities and Lines of Credit." The fair market value of fixed interest rate obligations are subject to interest rate risk. The fair market value of EMG's consolidated short-term debt and long-term obligations (including current portion) was $2.8 billion at June 30, 2010, compared to the carrying value of $4.1 billion.

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EDISON INTERNATIONAL PARENT AND OTHER

RESULTS OF OPERATIONS

Results of operations for Edison International parent and other includes amounts from other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.

Edison International parent and other income from continuing operations were $16 million and $43 million for the three months ended June 30, 2010 and 2009, respectively, and $11 million and $37 million for the six months ended June 30, 2010 and 2009, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flow

This section discusses Edison International (parent) and other cash flows from operating, financing and investing activities.

Condensed Statement of Cash Flows

	Six Months Ended June 30,

(in millions)	2010			2009

Cash flows used by operating activities	$	(21	)	$	(27	)
Cash flows provided (used) by financing activities		25			(274	)
Cash flows provided by investing activities		7			6

Net increase (decrease) in cash and equivalents	$	11		$	(295	)

Cash Flows Provided (Used) by Financing Activities

Financing activities for the first six months of 2010 were as follows:

•: Paid $205 million of (or $0.315 per share) dividends to Edison International common shareholders. These quarterly dividends represent an increase of $0.005 per share over quarterly dividends paid in 2009. In April 2010, the Board of Directors of Edison International declared a $0.315 per share quarterly dividend which was paid in July 2010.
•: Received $100 million of dividend payments from SCE.
•: Borrowed $130 million under Edison International's line of credit to fund interim working capital requirements.

Financing activities for the first six months of 2009 were as follows:

•: Paid $202 million of (or $0.31 per share) dividends to Edison International common shareholders. These quarterly dividends represent an increase of $0.005 per share over quarterly dividends paid in 2008.
•: Repaid a net $173 million of short-term debt.
•: Received $100 million of dividend payments from SCE.

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EDISON INTERNATIONAL (CONSOLIDATED)

CONTRACTUAL OBLIGATIONS

For a discussion of Edison International (Consolidated) contractual obligations, refer to "Edison International (Consolidated)—Contractual Obligations" in the year-ended 2009 MD&A. There have been no significant changes with respect to Edison International (Consolidated) contractual obligations since the filing of the 2009 Form 10-K, except as discussed in "EMG: Liquidity and Capital Resources—Contractual Obligations and Contingencies" and "SCE: Liquidity and Capital Resources—Contractual Obligations and Contingencies."

NEW ACCOUNTING GUIDANCE

New accounting guidance is discussed in "Edison International Notes to Consolidated Financial Statements Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to this item is included in the MD&A under the headings "SCE: Market Risk Exposures" and "EMG: Market Risk Exposures" and is incorporated herein by reference.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Edison International's management, under the supervision and with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of Edison International's disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, Edison International's disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There were no changes in Edison International's internal control over financial reporting (as that term is defined in Rules 13(a)-15(f) or 15(d)-15(f) under the Exchange Act) during the quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, Edison International's internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Homer City New Source Review Notice of Violation

Developments related to the Homer City New Source Review Notice of Violation are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Homer City New Source Review Notice of Violation—Recent Developments."

Midwest Generation New Source Review Lawsuit

Developments related to the Midwest Generation New Source Review Lawsuit are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Lawsuit—Recent Developments."

Mitsubishi Lawsuit

EME and Mitsubishi Power Systems Americas, Inc. are parties to a wind turbine generator supply agreement executed in March 2007 with respect to the purchase of 166 wind turbines and related services and warranties. Mitsubishi has delivered 83 wind turbines under the agreement. The remaining wind turbines, among other items, are under dispute.

EME filed a complaint on March 19, 2010, and an amended complaint on April 1, 2010, in the Superior Court of the State of California against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd with respect to a wind turbine generator supply agreement for the purchase of wind turbines and related services and warranties. EME's complaint alleges, among other things: (a) that the Mitsubishi entities fraudulently induced EME to enter into the supply agreement by misrepresenting the facts and circumstances surrounding Mitsubishi's rights to certain technology incorporated into the turbines; (b) that the Mitsubishi entities breached the implied covenant of good faith and fair dealing; (c) that the Mitsubishi entities breached their warranty obligations; (d) that the Mitsubishi entities repudiated the supply agreement when they failed to provide EME with adequate assurances of performance; and (e) that certain price escalation provisions in the supply agreement do not reflect the intent of the contracting parties.

The complaint asks the Court for an order finding the supply agreement void and unenforceable or, in the alternative, for an order reforming its price escalation provisions to conform to the contracting parties' intent. The complaint also requests an order of specific performance requiring the Mitsubishi entities to honor their warranties with respect to equipment already purchased, an award of monetary damages (including exemplary and punitive damages), and an accounting of all amounts due under the supply agreement, including reimbursement to EME of amounts previously paid for units it can no longer use and is excused from accepting, together with prejudgment interest, and such other relief as the Court may deem just and proper. In June 2010, EME filed a motion to amend its complaint to include, among other things, additional support for its claims.

The failure of the Mitsubishi entities to perform certain previously contracted services pertaining to the Taloga project, including delivery and commissioning of turbines still in storage, could delay the development of the Taloga project. If the Taloga project does not achieve commercial operation by March 31, 2011, subject to extension under certain circumstances, Taloga's offtaker could seek to terminate or renegotiate its power purchase agreement.

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Navajo Nation Litigation

Developments related to the Navajo Nation Litigation are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Navajo Nation Litigation."

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c): Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Period		(b) Average Price Paid per Share (or Unit) ¹


April 1, 2010 to April 30, 2010	247,095	$	33.78	—	—
May 1, 2010 to May 31, 2010	1,046,903	$	32.80	—	—
June 1, 2010 to June 30, 2010	603,223	$	32.68	—	—

Total	1,897,221	$	32.89	—	—

¹: The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill requirements in connection with Edison International's (i) 401(k) Savings Plan, (ii) Dividend Reinvestment and Direct Stock Purchase Plan, and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan terms or participant elections. The shares were never registered in Edison International's name and none of the shares purchased were retired as a result of the transactions.

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ITEM 6. EXHIBITS


10.1		Edison International Director Matching Gifts Program, as adopted June 24, 2010
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32		Statement Pursuant to 18 U.S.C. Section 1350
101		Financial statements from the quarterly report on Form 10-Q of Edison International for the quarter ended June 30, 2010, filed on August 5, 2010, formatted in XBRL: (i) the Consolidated Statements of Income (Loss); (ii) the Consolidated Statements of Comprehensive Income (Loss); (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; and (v) the Notes to the Consolidated Financial Statements

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SIGNATURE

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 thereunto duly authorized.


		EDISON INTERNATIONAL
		(Registrant)
		By:		/s/ MARK C. CLARKE Mark C. Clarke Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)

Date: August 5, 2010

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Part I. Financial Information Item 1. Financial Statements Note 1. Summary Of Significant Accounting Policies Note 2. Derivative Instruments and Hedging Activities Note 3. Liabilities and Lines Of Credit Note 4. Income Taxes Note 5. Compensation and Benefit Plans Note 6. Commitments and Contingencies Note 7. Consolidated Statements Of Changes in Equity Note 8. Accumulated Other Comprehensive Income Note 9. Supplemental Cash Flows Information Note 10. Fair Value Measurements Note 11. Regulatory Assets and Liabilities Note 12. Other Income and Expenses Note 13. Variable Interest Entities Note 14. Business Segments Item 2. Management's Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 6. Exhibits

Supplier name	Ticker
Honeywell International Inc.	HON
3M Company	MMM
General Electric Company	GE
Dominion Energy, Inc.	D
Duke Energy Corporation	DUK
Air Products and Chemicals, Inc.	APD
ABB Ltd	ABB
Waste Management, Inc.	WM
Eaton Corporation plc	ETN

EIX 10-Q Quarter ended June 30, 2010