Edgar Filing: EDISON INTERNATIONAL

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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 March 31, 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 May 3, 2010

Common Stock, no par value		325,811,206

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TABLE OF CONTENTS


GLOSSARY			i
PART I. FINANCIAL INFORMATION			1
ITEM 1. FINANCIAL STATEMENTS			1
	Consolidated Statements of Income		1
	Consolidated Statements of Comprehensive Income		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		16
	Note 4. Income Taxes		17
	Note 5. Compensation and Benefit Plans		18
	Note 6. Commitments and Contingencies		20
	Note 7. Consolidated Statement of Changes in Equity		30
	Note 8. Accumulated Other Comprehensive Income		31
	Note 9. Supplemental Cash Flows Information		32
	Note 10. Fair Value Measurements		32
	Note 11. Regulatory Assets and Liabilities		38
	Note 12. Other Income and Expenses		39
	Note 13. Variable Interest Entities		39
	Note 14. Business Segments		43
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			45
	FORWARD-LOOKING STATEMENTS		45
EDISON INTERNATIONAL OVERVIEW
	Introduction		47
	Highlights of Operating Results		47
	SCE Capital Program		48
	Environmental Developments		49
		Midwest Generation Environmental Compliance Plans and Costs	49
		California Renewable Energy Developments	49
		Once-Through Cooling	49
	EMG Renewables Program		50
		Mitsubishi Lawsuit	50
	Parent Company Liquidity		50

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SOUTHERN CALIFORNIA EDISON COMPANY
	RESULTS OF OPERATIONS				51
	Electric Utility Results of Operations				52
		Utility Earning Activities			53
			2010 vs. 2009		53
		Utility Cost-Recovery Activities			54
			2010 vs. 2009		54
		Supplemental Operating Revenue Information			54
		Effective Income Tax Rates			54
	LIQUIDITY AND CAPITAL RESOURCES				55
	Available Liquidity				55
		Debt Covenant			55
	Regulatory Proceedings				55
		Energy Efficiency Risk/Reward Incentive Mechanism			55
		2010 FERC Rate Case			56
	Dividend Restrictions				56
	Margin and Collateral Deposits				56
	Historical Consolidated Cash Flow				57
		Condensed Consolidated Statement of Cash Flows			57
			Cash Flows Provided by Operating Activities		57
			Cash Flows Provided (Used) by Financing Activities		57
			Cash Flows Used by Investing Activities		58
	Contractual Obligations and Contingencies				58
		Contractual Obligations			58
		Contingencies			58
			Environmental Remediation		58
	MARKET RISK EXPOSURES				58
	Interest Rate Risk				58
	Commodity Price Risk				59
		Natural Gas and Electricity Price Risk			59
	Credit Risk				59
EDISON MISSION GROUP
	RESULTS OF OPERATIONS				61
	Results of Continuing Operations				61
		Adjusted Operating Income (AOI) – Overview			62
		Adjusted Operating Income from Consolidated Operations			64
			Midwest Generation Plants		64
			Homer City Facilities		65
			Non-GAAP Disclosures – Fossil-Fueled Facilities		66
				Adjusted Operating Income	66
			Seasonal Disclosure – Fossil-Fueled Facilities		66
			Renewable Energy Projects		67
			Energy Trading		68
		Adjusted Operating Income from Leveraged Lease Activities			68
		Adjusted Operating Income from Lease Termination and Other			68
		Adjusted Operating Income from Unconsolidated Affiliates			68

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			Doga	68
			March Point	68
			Seasonal Disclosure	68
		Interest Related Income (Expense)		69
		Income Taxes		69
	Results of Discontinued Operations			69
	Derivative Instruments			69
		Unrealized Gains and Losses		69
		Fair Value Disclosures		70
	LIQUIDITY AND CAPITAL RESOURCES			71
	Available Liquidity			71
	Global Settlement			71
	Capital Investment Plan			72
		Estimated Expenditures for Existing Projects		72
		Estimated Expenditures for Future Projects		72
	Historical Consolidated Cash Flow			73
		Condensed Consolidated Statement of Cash Flows		73
			Consolidated Cash Flows Provided by Operating Activities	73
			Consolidated Cash Flows Used by Financing Activities	73
			Consolidated Cash Flows Provided (Used) by Investing Activities	73
	Credit Ratings			74
		Overview		74
		Credit Rating of EMMT		74
		Margin, Collateral Deposits and Other Credit Support for Energy Contracts		74
	Debt Covenants and Dividend Restrictions			75
	Dividend Restrictions in Major Financings			76
		Key Ratios of EME's Principal Subsidiaries Affecting Dividends		76
		EME's Senior Notes and Guaranty of Powerton-Joliet Leases		76
	Contractual Obligations and Contingencies			76
		Fuel Supply Contracts and Coal Transportation Agreements		76
		Midwest Generation New Source Review Lawsuit		76
	Off-Balance Sheet Transactions			76
	Environmental Matters and Regulations			77
	MARKET RISK EXPOSURES			77
	Commodity Price Risk			77
		Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities		77
		Capacity Price Risk		79
		Basis Risk		79
		Coal and Transportation Price Risk		80
		Emission Allowances Price Risk		80
	Credit Risk			81
	Interest Rate Risk			82
EDISON INTERNATIONAL PARENT AND OTHER
	RESULTS OF OPERATIONS			83

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	LIQUIDITY AND CAPITAL RESOURCES			83
	Historical Cash Flow			83
		Condensed Statement of Cash Flows		83
			Cash Flows Provided (Used) by Financing Activities	83
EDISON INTERNATIONAL (CONSOLIDATED)
	Contractual Obligations			84
	New Accounting Guidance			84
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				84
ITEM 4. CONTROLS AND PROCEDURES				84
	Disclosure Controls and Procedures			84
	Changes in Internal Control Over Financial Reporting			84
PART II. OTHER INFORMATION				85
ITEM 1. LEGAL PROCEEDINGS				85
	Homer City New Source Review Notice of Violation			85
	Midwest Generation New Source Review Lawsuit			85
	Mitsubishi Lawsuit			85
	Navajo Nation Litigation			85
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS				86
ITEM 6. EXHIBITS				87
SIGNATURE				88

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GLOSSARY

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


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
Fitch		Fitch Ratings
FTRs		firm transmission rights
Four Corners		coal-fired electric generating facility located in Farmington, New Mexico
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		Mohave Generating Station
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		Palo Verde Nuclear Generating Station
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
RPM		reliability pricing model
RTO		Regional Transmission Organization
S&P		Standard & Poor's Ratings Services

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San Onofre		San Onofre Nuclear Generating Station
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)
SO₂		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)

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



Consolidated Statements of Income	Edison International
	Three Months Ended March 31,
(in millions, except per-share amounts)	2010			2009

	(Unaudited)
Electric utility	$	2,159		$	2,189
Competitive power generation		652			624
Other		(1	)		(1	)

Total operating revenue		2,810			2,812

Fuel		295			387
Purchased power		608			540
Operations and maintenance		1,037			969
Depreciation, decommissioning and amortization		369			342
Lease terminations and other		3			21

Total operating expenses		2,312			2,259

Operating income		498			553
Interest and dividend income		19			10
Equity in income (loss) from partnerships and unconsolidated subsidiaries – net		18			(8	)
Other income		34			26
Interest expense – net of amounts capitalized		(168	)		(187	)
Other expenses		(8	)		(6	)

Income from continuing operations before income taxes		393			388
Income tax expense		150			122

Income from continuing operations		243			266
Income from discontinued operations – net of tax		6			3

Net income		249			269
Less: Net income attributable to noncontrolling interests		13			19

Net income attributable to Edison International common shareholders	$	236		$	250

Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	$	230		$	247
Income from discontinued operations, net of tax		6			3

Net income attributable to Edison International common shareholders	$	236		$	250

Basic earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding		326			326
Continuing operations	$	0.70		$	0.75
Discontinued operations		0.02			0.01

Total	$	0.72		$	0.76

Diluted earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities		328			327
Continuing operations	$	0.70		$	0.75
Discontinued operations		0.02			0.01

Total	$	0.72		$	0.76

Dividends declared per common share	$	0.315		$	0.310

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

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Consolidated Statements of Comprehensive Income			Edison International
			Three Months Ended March 31,
(in millions)			2010			2009

			(Unaudited)
Net income			$	249		$	269
Other comprehensive income, net of tax:
	Pension and postretirement benefits other than pensions:
		Net gain arising during the period		12			—
		Amortization of net (gain) loss included in net income		(8	)		2
		Prior service adjustment arising during the period		2			—
		Amortization of prior service adjustment		(2	)		—
	Unrealized gain on derivatives qualified as cash flow hedges:
		Unrealized holding gain arising during the period, net of income tax expense of $62 and $98 for 2010 and 2009, respectively		95			151
		Reclassification adjustments included in net income, net of income tax expense of $14 and $32 for 2010 and 2009, respectively		(20	)		(49	)

Other comprehensive income				79			104

Comprehensive income				328			373
Less: Comprehensive income attributable to noncontrolling interests				13			19

Comprehensive income attributable to Edison International			$	315		$	354

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

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

		(Unaudited)
ASSETS
Cash and equivalents		$	1,418		$	1,673
Short-term investments			10			10
Receivables, less allowances of $53 for uncollectible accounts at both dates			843			1,017
Accrued unbilled revenue			360			347
Inventory			522			533
Derivative assets			324			357
Restricted cash			66			69
Margin and collateral deposits			129			125
Regulatory assets			303			120
Deferred income taxes			—			3
Other current assets			292			176

Total current assets			4,267			4,430

Competitive power generation and other property – less accumulated depreciation of $1,669 and $2,231 at respective dates			4,917			5,147
Nuclear decommissioning trusts			3,248			3,140
Investments in partnerships and unconsolidated subsidiaries			527			216
Investments in leveraged leases			162			160
Other investments			98			91

Total investments and other assets			8,952			8,754

Utility plant, at original cost:
	Transmission and distribution		22,674			22,214
	Generation		2,680			2,667
Accumulated depreciation			(6,064	)		(5,921	)
Construction work in progress			2,790			2,701
Nuclear fuel, at amortized cost			314			305

Total utility plant			22,394			21,966

Derivative assets			223			268
Restricted deposits			44			43
Rent payments in excess of levelized rent expense under plant operating leases			1,083			1,038
Regulatory assets			4,675			4,139
Other long-term assets			719			806

Total long-term assets			6,744			6,294

Total assets		$	42,357		$	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)	March 31, 2010		December 31, 2009

	(Unaudited)
LIABILITIES AND EQUITY
Short-term debt	$	277	$	85
Current portion of long-term debt		46		377
Accounts payable		977		1,347
Accrued taxes		190		186
Accrued interest		215		196
Customer deposits		234		238
Derivative liabilities		179		107
Regulatory liabilities		288		367
Deferred income taxes		155		—
Other current liabilities		696		884

Total current liabilities		3,257		3,787

Long-term debt		11,025		10,437

Deferred income taxes		4,522		4,334
Deferred investment tax credits		100		102
Customer advances		112		119
Derivative liabilities		931		529
Pensions and benefits		2,090		2,061
Asset retirement obligations		3,274		3,241
Regulatory liabilities		3,521		3,328
Other deferred credits and other long-term liabilities		2,542		2,500

Total deferred credits and other liabilities		17,092		16,214

Total liabilities		31,374		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)		2,311		2,304
Accumulated other comprehensive income		116		37
Retained earnings		7,642		7,500

Total Edison International's common shareholders' equity		10,069		9,841
Noncontrolling interests		7		258
Preferred and preference stock of utility not subject to mandatory redemption		907		907

Total equity		10,983		11,006



Total liabilities and equity	$	42,357	$	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
		Three Months Ended March 31,
(in millions)		2010			2009

		(Unaudited)
Cash flows from operating activities:
Net income		$	249		$	269
Less: Income from discontinued operations			6			3

Income from continuing operations			243			266
Adjustments to reconcile to net cash provided by operating activities:
	Depreciation, decommissioning and amortization		369			342
	Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)		38			32
	Other amortization		24			26
	Lease terminations and other		3			21
	Stock-based compensation		7			5
	Equity in (income) loss from partnerships and unconsolidated subsidiaries – net		(18	)		8
	Distributions and dividends from unconsolidated entities		22			(3	)
	Deferred income taxes and investment tax credits		218			63
	Income from leveraged leases		(1	)		(11	)
Changes in operating assets and liabilities:
	Receivables		150			86
	Inventory		(2	)		4
	Restricted cash		3			—
	Margin and collateral deposits – net of collateral received		(6	)		(23	)
	Other current assets		(154	)		37
	Rent payments in excess of levelized rent expense		(45	)		(49	)
	Accounts payable		(138	)		(141	)
	Accrued taxes		(6	)		85
	Other current liabilities		(182	)		(44	)
	Derivative assets and liabilities – net		695			(220	)
	Regulatory assets and liabilities – net		(636	)		244
	Other assets		(11	)		(13	)
	Other liabilities		20			(32	)
Operating cash flows from discontinued operations			6			3

Net cash provided by operating activities			599			686

Cash flows from financing activities:
Long-term debt issued			547			750
Long-term debt issuance costs			(20	)		(10	)
Long-term debt repaid			(343	)		(179	)
Bonds repurchased			—			(219	)
Short-term debt financing – net			192			(585	)
Stock-based compensation – net			(1	)		1
Dividends and distributions to noncontrolling interests			(13	)		(25	)
Dividends paid			(103	)		(101	)

Net cash provided (used) by financing activities		$	259		$	(368	)

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

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Consolidated Statements of Cash Flows	Edison International
	Three Months Ended March 31,
(in millions)	2010			2009

	(Unaudited)
Cash flows from investing activities:
Capital expenditures	$	(951	)	$	(785	)
Purchase of interest in acquired companies		—			(6	)
Proceeds from termination of leases		—			121
Proceeds from sale of nuclear decommissioning trust investments		286			658
Purchases of nuclear decommissioning trust investments and other		(335	)		(700	)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment		32			10
Maturities and sale of short-term investments		2			1
Purchase of short-term investments		(1	)		(1	)
Investments in other assets		(55	)		11

Net cash used by investing activities		(1,022	)		(691	)

Effect of consolidation of variable interest entities		5			—
Effect of deconsolidation of variable interest entities		(96	)		—

Net decrease in cash and equivalents		(255	)		(373	)
Cash and equivalents, beginning of period		1,673			3,916

Cash and equivalents, end of period	$	1,418		$	3,543

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS		Edison International

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 its 2009 Annual Report on 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 month period ended March 31, 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 $1.05 billion and $1.46 billion at March 31, 2010 and December 31, 2009, respectively. The carrying value of cash equivalents equals the fair value, as all investments have maturities of less than three months. For further discussion of money market funds, see Note 10.

Edison International has a cash management program under which the ending daily cash balance in its primary disbursement accounts are temporarily invested until required for check clearing. Edison International reclassified $240 million and $224 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at March 31, 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 March 31,

(in millions)	2010			2009

	(Unaudited)
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	230		$	247
Participating securities dividends		(1	)		(2	)

Income from continuing operations available to common shareholders	$	229		$	245

Weighted average common shares outstanding		326			326

Basic earnings per share – continuing operations	$	0.70		$	0.75

Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	229		$	245
Income impact of assumed conversions		1			—

Income from continuing operations available to common shareholders and assumed conversions	$	230		$	245

Weighted average common shares outstanding		326			326
Incremental shares from assumed conversions		2			1

Adjusted weighted average shares – diluted		328			327

Diluted earnings per share – continuing operations	$	0.70		$	0.75

Stock-based compensation awards to purchase 5,998,238 and 8,660,629 shares of common stock for the three months ended March 31, 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.

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 March 31, 2010 and December 31, 2009 consisted of the following:

(in millions)	March 31, 2010		December 31, 2009


	(Unaudited)
Coal, gas, fuel oil and raw materials	$	155	$	158
Spare parts, materials and supplies		367		375

Total	$	522	$	533

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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)		March 31, 2010		December 31, 2009


		(Unaudited)
Collateral provided to counterparties:
	Offset against derivative liabilities	$	15	$	49
	Reflected in margin and collateral deposits		129		125
Collateral received from counterparties:
	Offset against derivative assets		210		124
	Reflected in other current liabilities		56		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. Requirements, 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

Accounting pronouncements recently issued by the FASB (including its Emerging Issues Task Force), the American Institute of Certified Public Accountants and the SEC that were effective after March 31, 2010 are not expected to have a material effect on Edison International's consolidated results of operations, financial position or cash flows.

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:

		March 31, 2010		December 31, 2009


Commodity	Unit of Measure	Economic Hedges		Economic Hedges

		(Unaudited)
Electricity options, swaps and forward arrangements	GWh		14,943		14,868
Natural gas options, swaps and forward arrangements	Bcf		251		266
Congestion revenue rights	GWh		180,518		195,367
Tolling arrangements¹	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 March 31, 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	$	132		$	141	$	273		$	190		$	920	$	1,110		$	837
Netting and collateral		(2	)		—		(2	)		(12	)		—		(12	)		(10	)

Total	$	130		$	141	$	271		$	178		$	920	$	1,098		$	827

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
Netting and collateral		—		—		—		—		—		—		—

Total	$	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 from ratepayers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are deferred and are not recognized as purchased-power expense and therefore do not affect 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 March 31,


(in millions)	2010			2009

	(Unaudited)
Realized gains/(losses)	$	(24	)	$	(98	)
Unrealized gains/(losses)		(581	)		333

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 $213 million and $91 million, as of March 31, 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 March 31, 2010, SCE would be required to post $16 million of collateral.

Competitive Power Generation

EMG uses derivative instruments to reduce its 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 the consolidated balance sheets with offsetting changes recorded in the consolidated statements of income. For transactions that qualify for accounting hedge treatment, the fair value is recognized, to the extent effective, on the 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 sheet as derivative assets or liabilities. Changes in fair value are recognized in the consolidated statements of income.

Notional Volumes of Derivative Instruments

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

March 31, 2010


				Hedging Activities

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

				(Unaudited)
Electricity	Forwards/Futures	Sales	GWh		31,324	¹		23,042	³		25,986
Electricity	Forwards/Futures	Purchases	GWh		65	¹		22,364	³		26,011
Electricity	Capacity	Sales	MW-Day (in thousands)		190	²		1	²		395	²
Electricity	Capacity	Purchases	MW-Day (in thousands)		4	²		1	²		538	²
Electricity	Congestion	Sales	GWh		—			136	⁴		7,871	⁴
Electricity	Congestion	Purchases	GWh		—			719	⁴		131,579	⁴
Natural gas	Forwards/Futures	Sales	BCF		—			2.5			40.0
Natural gas	Forwards/Futures	Purchases	BCF		—			—			37.1
Fuel oil	Forwards/Futures	Sales	Barrels		—			—			234,000
Fuel oil	Forwards/Futures	Purchases	Barrels		—			375,000			244,000

(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
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 gross fair value of derivative instruments:

March 31, 2010

		Derivative Assets									Derivative Liabilities

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

		(Unaudited)
Non-trading activities
	Cash flow hedges	$	292		$	44		$	336		$	17		$	9		$	26		$	310
	Economic hedges		257			4			261			231			3			234			27
Trading activities			315			146			461			255			75			330			131

			864			194			1,058			503			87			590			468
Netting and collateral received			(670	)		(112	)		(782	)		(502	)		(75	)		(577	)		(205	)

Total		$	194		$	82		$	276		$	1		$	12		$	13		$	263

December 31, 2009

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			(479	)		(55	)		(534	)		(426	)		(32	)		(458	)		(76	)

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

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 Activity¹ Three Months Ended March 31,

	Cash Flow Hedge Activity¹ Three Months Ended March 31,						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		157			249
Reclassification from accumulated other comprehensive income to net income		(34	)		(81	)	Operating revenue

Accumulated other comprehensive income derivative gain at March 31	$	298		$	566

¹: Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at March 31, 2010 and 2009 were $180 million and $342 million, respectively.

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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 net gains of $9 million and none during the first quarters of 2010 and 2009, respectively, representing the amount of cash flow hedge ineffectiveness and are reflected in operating revenues on the consolidated statements of income.

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

		Three Months Ended March 31,

	Income Statement Location	Three Months Ended March 31,
(in millions)	Income Statement Location	2010			2009

		(Unaudited)
Economic hedges	Operating revenue	$	(4	)	$	14
	Fuel expense		1			—
Trading activities	Operating revenue		47			10

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 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 March 31, 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. The bond proceeds were used to repay commercial paper borrowings and for general corporate purposes.

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 $135.3 million construction loan that is required to be converted to a 15-year amortizing term loan by May 31, 2011, subject to specific conditions. As of March 31, 2010, there was $47 million outstanding under the construction loan at a weighted average interest rate of 3.24%.

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EMG consolidated the Ambit project in the first quarter of 2010. At March 31, 2010, this project had $71 million of bonds payable. 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 quarter ended March 31, 2010 was 0.23%. Annual maturities of this debt at March 31, 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

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 March 31, 2010, the outstanding short-term debt was $180 million at a weighted-average interest rate of .28%. This short-term debt was supported by a $2.4 billion credit line. At December 31, 2009, the outstanding short-term debt was zero.

Edison International (parent) short-term debt is generally used to finance operating expenses and dividends. At March 31, 2010, the outstanding short-term debt was $97 million at a weighted-average interest rate of .61%. At December 31, 2009, the outstanding short-term debt was $85 million at a weighted-average interest rate of ..60%.

Letters of Credit

As of March 31, 2010, letters of credit under EME and its subsidiaries' credit facilities aggregated $128 million and are scheduled to expire as follows: $77 million in 2010 and $51 million in 2011. Letters of credit under SCE's credit facility aggregated $82 million and are scheduled to expire in 2010.

Note 4. Income Taxes

Edison International's effective tax rates were 39% and 33% (excluding income attributable to non-controlling interests) for the three months ended March 31, 2010 and 2009, respectively. The increase in the effective tax rate was primarily due to a $39 million non-cash charge recorded in the first quarter of 2010 to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010, partially offset by higher property-related flow-through tax deductions in 2010 at SCE. 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.

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.

EMG applied for U.S. Treasury grants in January 2010 for Phase II of the Goat Wind and High Lonesome wind projects in lieu of investment tax credits and received proceeds, pursuant to these applications, of approximately $92 million from the U.S. Treasury Department in April 2010.

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Accounting for Uncertainty in Income Taxes

Unrecognized tax benefits increased $119 million during the first quarter of 2010 mainly as a result of tax positions taken for a prior period.

Note 5. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

For the three months ended March 31, 2010, Edison International made 2010 plan year contributions of $22 million and expects to make $86 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 March 31,


(in millions)	2010			2009

	(Unaudited)
Service cost	$	34		$	32
Interest cost		54			52
Expected return on plan assets		(52	)		(42	)
Amortization of prior service cost		2			4
Amortization of net loss		7			14

Expense under accounting standards		45			60
Regulatory adjustment – deferred		(14	)		(37	)

Total expense recognized	$	31		$	23

Postretirement Benefits Other Than Pensions

For the three months ended March 31, 2010, Edison International made 2010 plan year contributions of $5 million and expects to make $40 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 March 31,


(in millions)	2010			2009

	(Unaudited)
Service cost	$	8		$	11
Interest cost		31			36
Expected return on plan assets		(25	)		(21	)
Amortization of prior service cost (credit)		(9	)		(8	)
Amortization of net loss		8			16

Total expense	$	13		$	34

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) was $8 million and $5 million for the three months ended March 31, 2010 and 2009, respectively. The income tax benefit recognized in the consolidated statements of income was $3 million and $2 million for the three months ended March 31, 2010 and 2009, respectively. Consistent with SCE's 2009 GRC, no stock-based compensation was capitalized beginning in 2009. Excess tax benefits included in "Stock-based compensation – net" in the financing section of the consolidated statements of cash flows were $1 million and $2 million for the three months ended March 31, 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		3,614,245			33.30
Forfeited		(83,309	)		30.68
Exercised		(192,752	)		24.06

Outstanding at March 31, 2010		20,706,216			32.43		6.80

Vested and expected to vest at March 31, 2010		20,202,155			32.44		6.75	$	108,832,209

Exercisable at March 31, 2010		12,034,622			32.40		5.25		75,496,476

Cash outflows to purchase Edison International shares in the open market to settle stock option exercises were $7 million and $4 million for the three months ended March 31, 2010 and 2009, respectively. Cash inflows from participants to exercise stock options were $5 million and $3 million for

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the three months ended March 31, 2010 and 2009, respectively. The tax benefit realized from options exercised was less than $1 million for each of the three months ended March 31, 2010 and 2009.

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		136,831			32.50
Forfeited		(66,625	)		56.45

Nonvested at March 31, 2010		413,658			31.06

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		136,831
Forfeited		(66,625	)

Nonvested at March 31, 2010		413,658		$	25.96

There were no performance shares settled in 2009 or 2010.

Note 6. Commitments and Contingencies

Other Commitments

At March 31, 2010, EMG's subsidiaries had firm commitments to spend approximately $462 million during the remainder of 2010 on capital and construction expenditures. These expenditures primarily relate to the construction of wind projects and non-environmental improvements at the fossil-fueled facilities. 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 March 31, 2010, EMG had commitments to purchase 129 wind turbines (268 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 pending construction and turbines subject to a legal dispute. EMG has payment commitments related to the 59 wind turbines of $82 million remaining in 2010 and $4 million due in 2011.

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EMG's turbine supply agreement with Mitsubishi Power Systems Americas, Inc. is subject to a legal dispute. EMG has made deposits of $68 million for the purchase of 83 wind turbines (199 MW) under this agreement. The resolution of this dispute could impact future payments due under this agreement. The remaining payments under this agreement subject to dispute are $289 million, mostly related to undelivered wind turbines. For additional information regarding this dispute, see "Legal Proceedings" in Part II of this quarterly report.

At March 31, 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 $1.0 billion, summarized as follows: $351 million for the remainder of 2010, $389 million in 2011, $247 million in 2012, and $33 million in 2013.

At March 31, 2010, Midwest Generation and Homer City 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 $369 million, summarized as follows: $198 million for the remainder of 2010, and $171 million in 2011.

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

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 obligation 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

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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 March 31, 2010. Midwest Generation had recorded a $50 million liability at March 31, 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 the obligations 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 March 31, 2010, EME had recorded a liability of $58 million (of which $20 million is classified as a current liability) 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

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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.

Mountainview Filter Cake Indemnity

SCE's 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 guarantee.

Other Edison International Indemnities

Edison International 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. Edison International's obligations under these agreements may be limited in terms of time and/or amount, and in some instances Edison International 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. Edison International 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.

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Environmental Developments

For a more complete discussion of Edison International's environmental contingencies, refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K.

Midwest Generation Environmental Compliance Plans and Costs

During the first quarter of 2010, Midwest Generation continued its permitting and planning activities for installation of SNCR technology on multiple units to meet the NO_x portion of the Combined Pollutant Standard ("CPS"). In addition, work continues on analysis and evaluation of FGD technology using dry scrubbing with sodium-based sorbents as a method to comply with the SO₂ portion of the CPS. Midwest Generation may combine the use of dry scrubbing using sodium-based sorbents with upgrades to unit particulate removal systems to meet environmental regulations.

Testing of FGD technology based on dry scrubbing with sodium-based sorbents demonstrated significant reductions in SO₂ emissions when using the low-sulfur coal employed by Midwest Generation; however, further analysis and evaluation is required to determine the appropriate method to comply with the SO₂ portion of the CPS. Use of FGD technology based on dry scrubbing with sodium-based sorbents in combination with Midwest Generation's use of 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 the plants. If Midwest Generation utilizes dry scrubbing with sodium-based sorbents to meet environmental regulations, it will likely need to upgrade its particulate removal systems.

Midwest Generation cannot predict what specific method of SO₂ removal will be used or the total costs that will be incurred to comply with the CPS. A decision regarding whether or not to proceed with the above or other approaches to compliance remains subject to further analysis and the evaluation of factors, such as market conditions, regulatory and legislative developments, and forecasted capital and operating costs. 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, the particular controls that will be installed, and the resulting capital commitments may not occur until 2012 for some of the units and potentially later for others. Midwest Generation could also elect to shut down units, instead of installing controls to be in compliance with the CPS. Midwest Generation continues to evaluate various scenarios and cannot predict the extent of shutdowns and retrofits or the particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS.

Homer City Environmental Issues and Capital Resource Limitations

Homer City operates selective catalytic reduction equipment on all three units to reduce NO_x emissions, operates FGD equipment on Unit 3 to reduce SO₂ 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 future environmental regulations. 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 Developments

The nature of future environmental regulation and legislation will have a substantial impact on Edison International and its subsidiaries. Edison International believes that resolution of current uncertainties about the future, through well-balanced and appropriately flexible regulation and legislation, is needed to support the necessary evolution of the electric industry into using cleaner, more efficient infrastructure and to attract the capital ultimately needed for this effort. Legislative, regulatory, and legal developments related to potential controls over greenhouse gas-emissions in the United States are ongoing. Actions to limit or reduce greenhouse gas emissions could significantly increase the cost of generating electricity from fossil fuels. In the case of utilities, like SCE, these costs are generally borne by customers, whereas the increased costs for competitive generators, like EMG, may not be recovered through market prices for electricity.

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 gas-fired 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-fuel plants that use ocean water in once-through cooling systems. As a consequence, system reliability and the cost of electricity may be impacted 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 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 additional costs would be recovered from customers or that Edison International's financial position, results of operations and cash flows would not be materially affected.

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 costs for site investigations, remediation, operations and maintenance, monitoring and site closure.

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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 March 31, 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 $42 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 $171 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 less than $1 million and $3 million for the three months ended March 31, 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.

Federal and State Income Taxes

Edison International's federal income tax returns are currently under active examination by the IRS for tax years 2003 through 2006 and are subject to examination through tax year 2009. Edison International's California and other state income tax returns remain open for tax years 1986 through 2009.

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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 revenue requirement by $107 million, or 24%, over the 2009 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 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. SCE may seek a rehearing of the order. 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. The 2010 CWIP revenue requirements are expected to be collected in rates beginning on June 1, 2010. The collected 2008 and 2009 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

On May 6, 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.

Background

On June 12, 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 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. EMG cannot predict the outcome of this matter or estimate the impact on its facilities, 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.

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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. The Court gave the plaintiffs a deadline of May 14, 2010 to amend their complaint.

On April 2, 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.

Background

On August 3, 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 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 best available control technology ("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.

On August 27, 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

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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 EMG. EMG cannot predict the outcome of these matters or estimate the impact on its facilities, 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.

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 utilities 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.

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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.

On January 29, 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. The trial was completed in April 2009 but no decision has been issued. SCE cannot predict the outcome of this proceeding or when a decision will be issued by the Court.

Note 7. Consolidated Statement of Changes in Equity

The following table provides the changes in equity for the three months ended March 31, 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		—		—		236			236			—			13			249
Other comprehensive income		—		79		—			79			—			—			79
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 ($0.315 per share)		—		—		(103	)		(103	)		—			—			(103	)
Dividends, distributions to noncontrolling interests and other		—		—		—			—			(2	)		(13	)		(15	)
Stock-based compensation – net		2		—		(2	)		—			—			—			—
Noncash stock-based compensation and other		5		—		(4	)		1			—			—			1

Balance at March 31, 2010	$	2,311	$	116	$	7,642		$	10,069		$	7		$	907		$	10,983

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The following table provides the changes in equity for the three months ended March 31, 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		—		—		250			250			6			13			269
Other comprehensive income		—		104		—			104			—			—			104
Common stock dividends declared ($0.31 per share)		—		—		(101	)		(101	)		—			—			(101	)
Dividends, distributions to noncontrolling interests and other		—		—		—			—			(14	)		(13	)		(27	)
Stock-based compensation – net		2		—		(1	)		1			—			—			1
Noncash stock-based compensation and other		4		—		(7	)		(3	)		—			—			(3	)

Balance at March 31, 2009	$	2,278	$	271	$	7,219		$	9,768		$	277		$	907		$	10,952

Note 8. Accumulated Other Comprehensive Income

Edison International's accumulated other comprehensive income consists of:

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


	(Unaudited)
Balance at December 31, 2009	$	105	$	(70	)	$	2	$	37
Current period change		75		4			—		79

Balance at March 31, 2010	$	180	$	(66	)	$	2	$	116

Included in accumulated other comprehensive income at March 31, 2010 was $183 million, net of tax, of unrealized gains on commodity-based cash flow hedges. 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 $160 million of the unrealized gains on cash flow hedges, net of tax, at March 31, 2010 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.

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Note 9. Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

			Three Months Ended March 31,

(in millions)			2010		2009

			(Unaudited)
Cash payments (receipts) for interest and taxes
	Interest – net of amounts capitalized		$	137	$	137
	Tax payments (receipts)			10		(33	)
Noncash investing and financing activities
	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			8		8

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 non-performance 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 traded or over-the-counter traded.

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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 (ICE 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 financial natural gas swaps, fixed to floating swaps, and natural gas physical trades for which SCE obtains the applicable Henry Hub and basis 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 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. SCE has Level 3 fixed to floating swaps for which SCE obtains the applicable Henry Hub and basis forward market prices from the New York Mercantile Exchange. However, these swaps have contract terms that extend beyond observable market data and the unobservable inputs incorporated in the fair value determination are considered significant compared to the overall swap's fair value.

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 is 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.

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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 $11 million, respectively, at March 31, 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.

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

			As of March 31, 2010

(in millions)			Level 1			Level 2			Level 3			Netting and collateral¹			Total

			(Unaudited)
Assets at Fair Value
	Money market funds²		$	1,114		$	—		$	—		$	—		$	1,114

	Derivative contracts
		Electricity		—			342			413			(279	)		476
		Natural gas		5			3			70			(7	)		71
		Fuel oil		11			—			—			(11	)		—

		Sub-total of commodity contracts		16			345			483			(297	)		547

	Long-term disability plan			9			—			—			—			9

	Nuclear decommissioning trusts
		Stocks³		1,846			—			—			—			1,846
		Municipal bonds		—			652			—			—			652
		Corporate bonds⁴		—			403			—			—			403
		U.S. government and agency securities		253			49			—			—			302
		Short-term investments, primarily cash equivalents⁵		12			23			—			—			35

		Sub-total of nuclear decommissioning trusts		2,111			1,127			—			—			3,238

Total assets⁶			$	3,250		$	1,472		$	483		$	(297	)	$	4,908

Liabilities at Fair Value
	Derivative contracts:
		Electricity	$	—		$	(80	)	$	(828	)	$	87		$	(821	)
		Natural gas		(1	)		(246	)		(52	)		15			(284	)

		Sub-total of commodity contracts		(1	)		(326	)		(880	)		102			(1,105	)

		Interest rate contracts		—			(6	)		—			—			(6	)

Net assets (liabilities)			$	3,249		$	1,140		$	(397	)	$	(195	)	$	3,797

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			As of December 31, 2009

(in millions)			Level 1			Level 2			Level 3			Netting and Collateral¹			Total

			(Unaudited)
Assets at Fair Value
	Money market funds²		$	1,526		$	—		$	—		$	—		$	1,526

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

		Sub-total of commodity contracts		17			245			516			(153	)		625

	Long-term disability plan			8			—			—			—			8

	Nuclear decommissioning trusts
		Stocks³		1,772			—			—			—			1,772
		Municipal bonds		—			634			—			—			634
		Corporate bonds⁴		—			393			—			—			393
		U.S. government and agency securities		240			68			—			—			308
		Short-term investments, primarily cash equivalents⁵		1			14			—			—			15

		Sub-total of nuclear decommissioning trusts		2,013			1,109			—			—			3,122

Total assets⁶			$	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	)

		Sub-total 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 March 31, 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 March 31, 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 March 31, 2010 and December 31, 2009, this category included $52 million and $50 million, respectively, for collateralized mortgage obligations and other asset backed securities.
⁵: Excludes net assets of $10 million and $18 million of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases at March 31, 2010 and December 31, 2009, respectively.
⁶: Excludes $32 million of cash surrender value of life insurance investments for deferred compensation at March 31, 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 March 31,

(in millions)		2010			2009

		(Unaudited)
Fair value, net asset (liability) at beginning of period		$	62		$	(305	)
Total realized/unrealized gains (losses):
	Included in earnings¹		45			146
	Included in regulatory assets and liabilities²		(487	)		388
	Included in accumulated other comprehensive income		6			—
Purchases and settlements, net			(22	)		(85	)
Transfers into or out of Level 3			(1	)		(3	)

Fair value, net asset (liability) at end of period		$	(397	)	$	141

Change during the period in unrealized gains (losses) related to assets and liabilities held at the end of the period³		$	(422	)	$	464

¹: Reported in "Competitive power generation" revenue on Edison International's consolidated statement of income.
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 $46 million and $73 million for the three months ended March 31, 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 1st quarter 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 Dates¹		March 31, 2010		December 31, 2009		March 31, 2010		December 31, 2009

			(Unaudited)
Stocks		–	$	828	$	822	$	1,846	$	1,772
Municipal bonds		2010 – 2047		559		545		652		634
Corporate bonds		2010 – 2044		325		309		403		393
U.S. government and agency securities		2010 – 2039		284		287		302		308
Short-term investments and receivables/payables		2010		43		33		45		33

Total			$	2,039	$	1,996	$	3,248	$	3,140

¹: Maturity dates as of March 31, 2010.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Realized gains were $21 million and $74 million for the three months ended March 31, 2010 and 2009, respectively. Realized losses were zero and $62 million for the three months ended March 31, 2010 and 2009, respectively. Proceeds from sales of securities (which are reinvested) were $286 million and $658 million for the three months ended March 31, 2010 and 2009, respectively. Unrealized holding gains, net of losses, were $1.2 billion and $1.1 billion at March 31, 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 March 31,

(in millions)	2010			2009

	(Unaudited)
Balance at beginning of period	$	3,140		$	2,524
Realized gains – net		21			12
Unrealized gains – net		62			(73	)
Other-than-temporary impairment		(3	)		(94	)
Interest, dividends, contributions and other		28			30

Balance at end of period	$	3,248		$	2,399

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:

	Carrying Amount				Fair Value


(in millions)	March 31, 2010		December 31, 2009		March 31, 2010		December 31, 2009

	(Unaudited)
Long-term debt, including current portion	$	11,071	$	10,814	$	10,435	$	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.

Note 11. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)	March 31, 2010		December 31, 2009


	(Unaudited)
Current:
Regulatory balancing accounts	$	166	$	94
Energy derivatives		136		25
Other		1		1

		303		120

Long-term:
Regulatory balancing accounts		51		43
Deferred income taxes – net		1,640		1,561
Unamortized nuclear investment – net		325		340
Nuclear-related ARO investment – net		253		258
Unamortized coal plant investment – net		73		73
Unamortized loss on reacquired debt		282		287
Pensions and other postretirement benefits		1,009		1,014
Energy derivatives		826		357
Environmental remediation		39		36
Other		177		170

		4,675		4,139

Total Regulatory Assets	$	4,978	$	4,259

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Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	March 31, 2010		December 31, 2009


	(Unaudited)
Current:
Regulatory balancing accounts	$	282	$	363
Other		6		4

		288		367

Long-term:
Regulatory balancing accounts		750		642
ARO		230		171
Costs of removal		2,541		2,515

		3,521		3,328

Total Regulatory Liabilities	$	3,809	$	3,695

Note 12. Other Income and Expenses

Other income and expenses are as follows:

	Three Months Ended March 31,

(in millions)	2010			2009

	(Unaudited)
Other Income:
Equity AFUDC	$	27		$	16
Increase in cash surrender value of life insurance policies		6			6
Other		1			4

Total utility other income		34			26

Competitive power generation and parent		—			—

Total other income	$	34		$	26

Other Expense:
Civic, political and related activities and donations	$	5		$	4
Other		5			4

Total utility other expense		10			8

Competitive power generation and parent		(2	)		(2	)

Total other expenses	$	8		$	6

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 model for determining which reporting entity, if any, has a controlling financial interest in a VIE with a

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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 March 31, 2010 and December 31, 2009, EMG had majority interests in 15 wind projects with a total generating capacity of 700 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 Edison International. Upon the application of the new authoritative guidance effective January 1, 2010, Edison International deconsolidated two of these projects. See further discussion below in "—Projects that are not Consolidated." In determining that EMG was the primary beneficiary of the 13 projects consolidated at March 31, 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)		March 31, 2010		December 31, 2009


		(Unaudited)
Current assets		$	62	$	73
Net property, plant and equipment¹			690		944
Other long-term assets			2		2

	Total assets¹	$	754	$	1,019

Current liabilities		$	15	$	17
Long-term obligations net of current maturities			19		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 $80 million and $81 million at March 31, 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 contractual agreements (including naming the executive director) and has the obligation to absorb losses and the right to receive benefits from the project. Therefore, under the new guidance, EMG is the primary beneficiary

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which resulted in the consolidation of the Ambit project by Edison International. Total assets consolidated at January 1, 2010 and March 31, 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 non performance 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, so there is no significant potential maximum exposure to loss as a result of its involvement with the VIEs. For contracts accounted for as a derivative, the potential maximum exposure is limited to the derivative asset balance in the tables below. The aggregate capacity dedicated to SCE for these VIE projects was 1,749 MW at March 31, 2010 and the amounts that SCE paid to these projects were $125 million and $116 million for the three-month periods ended March 31, 2010 and March 31, 2009, respectively. These amounts are recoverable in customer rates.

The following table summarizes as of March 31, 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	$	—	$	—	$	32	$	700	$	—
Accounts Payable		—		—		40		—		—

Total	$	—	$	—	$	72	$	700	$	—

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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

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 March 31, 2010 and December 31, 2009, EMG had five 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. Commercial and operating activities are jointly controlled by a management committee of each VIE. In addition, the executive director of these projects is provided by EMG's partner. Accordingly, EMG continues to account for its variable interests under the equity method.

As noted above, 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 March 31, 2010:

	March 31, 2010

(in millions)	Investment		Maximum Exposure

	(Unaudited)
Natural gas-fired projects	$	333	$	333
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 March 31, 2010, entities which EMG has accounted for under the equity method had indebtedness of $144 million, of which $60 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. As discussed above, commercial and operating activities are jointly controlled by a management committee of each VIE. 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 segments. 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 March 31,

(in millions)	2010			2009

	(Unaudited)
Operating Revenue (Loss):
Electric utility	$	2,159		$	2,189
Competitive power generation		652			624
Parent and other²		(1	)		(1	)

Consolidated Edison International		2,810			2,812

Net Income (Loss) attributable to Edison International:
Electric utility		164			208
Competitive power generation¹		77			48
Parent and other²		(5	)		(6	)

Consolidated Edison International	$	236		$	250

Segment balance sheet information was:

(in millions)	March 31, 2010			December 31, 2009


	(Unaudited)
Total Assets:
Electric utility	$	32,975		$	32,474
Competitive power generation		9,787			9,543
Parent and other²		(405	)		(573	)

Consolidated Edison International	$	42,357		$	41,444

¹: Includes earnings from discontinued operations of $6 million and $3 million for the three months ended March 31, 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.

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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, in each case, 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;
•: risk of counterparty default in hedging transactions or power-purchase and fuel contracts;
•: 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 Edison International's Annual Report on Form 10-K for the year-ended December 31, 2009 ("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 months ended March 31, 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 months ended March 31, 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 five sections:

•: Highlights of operating results,
•: SCE capital program,
•: 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 on Form 10-K for additional information on these topics.

Highlights of Operating Results

		Three Months Ended March 31,

(in millions)		2010			2009			Change

Net Income attributable to Edison International
	SCE	$	164		$	208		$	(44	)
	EMG		77			48			29
	Edison International Parent and Other		(5	)		(6	)		1

	Edison International Consolidated		236			250			(14	)

Non-Core Items
	SCE – tax impact of health care legislation		(39	)		—			(39	)
	EMG – lease terminations¹		—			(11	)		11
	EMG discontinued operations		6			3			3

	Total non-core items		(33	)		(8	)		(25	)

Core Earnings
	SCE		203			208			(5	)
	EMG		71			56			15
	Edison International Parent and Other		(5	)		(6	)		1

	Edison International Consolidated	$	269		$	258		$	11

¹: Includes the impact of termination of two of Edison Capital's cross-border leases.

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

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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 decreased from 2009 primarily due to higher operating expense, including the impact of curtailed spending in the first quarter of last year until the 2009 CPUC GRC decision was received in March 2009. This decrease was almost entirely offset by rate base growth and higher capitalized financing costs (AFUDC).

EMG's 2010 core earnings increased from 2009 primarily due to higher distributions from EMG's Doga and March Point natural gas facilities and higher trading income. Mainly offsetting this increase were lower results from EMG's merchant coal plants driven primarily by lower energy prices and higher 2009 unrealized gains, partially offset by lower emission costs and higher capacity prices. Renewable project income was lower mainly due to less wind.

Consolidated non-core items for Edison International included:

•: A non-cash charge of $39 million 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.
•: An after-tax loss of $11 million in the first quarter of 2009 from termination of two of Edison Capital's cross-border leases.

SCE Capital Program

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

•: Upgrading and constructing new transmission lines to expand capacity to utilize 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 and Unit 2 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 Edison SmartConnect™. During the first quarter SCE installed approximately 344,000 smart meters, with cumulative installations totaling approximately 495,000.

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SCE continues to plan to utilize much of the cash generated from its operations and issuance of additional debt and preferred equity for its capital program. During the first quarter of 2010, SCE issued $500 million of long-term debt that matures in 2040.

SCE's capital investments (including accruals) during the first quarter of 2010 totaled $640 million. 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.

Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

Midwest Generation cannot predict what specific method of SO₂ removal will be used or the total costs that will be incurred to comply with the CPS. A decision regarding whether or not to proceed with the above or other approaches to compliance remains subject to further analysis and the evaluation of factors, such as market conditions, regulatory and legislative developments and forecasted capital and operating costs. 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, the particular controls that will be installed, and the resulting capital commitments may not occur until 2012 for some of the units and potentially later for others. Midwest Generation could also elect to shut down units, instead of installing controls, to be in compliance with the CPS. Midwest Generation continues to evaluate various scenarios and cannot predict the extent of shutdowns and retrofits or the particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS.

California Renewable Energy Developments

In March 2010, CARB issued its preliminary draft Renewable Electricity Standard that would require most retail sellers of electricity in California to procure 33% of their electricity from eligible renewable energy resources by 2020. CARB is seeking comments on its draft from stakeholders and plans to issue proposed regulations during the summer of 2010. 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

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electricity may be impacted 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.

EMG Renewables Program

EMG had a development pipeline of potential wind projects with projected installed capacity of approximately 4,000 MW at March 31, 2010. EMG has purchase contracts for 102 MW of wind turbines that are to be used for projects not yet under construction as of March 31, 2010, excluding turbine purchase contracts for 199 MW of wind turbines that are subject to a dispute. EMG plans to deploy these wind turbines when projects meet acceptable financial thresholds, have long-term power sales agreements, and can attract long-term project financing. 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.

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 current cash flows for their respective capital needs, Edison International (parent) expects to incur additional borrowings to fund its own activities.

At March 31, 2010, Edison International (parent) had approximately $22 million of cash and equivalents on hand. The following table summarizes the status of the Edison International (parent) credit facility at March 31, 2010:

(in millions)	Edison International (parent)


Commitment	$	1,426
Outstanding borrowings		(97	)
Outstanding letters of credit		—

Amount available	$	1,329

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 March 31, 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 incurred or provide mechanisms to track and recover or refund differences in forecasted and actual amounts. Balancing accounts 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, public purpose related program costs (including energy efficiency and demand-side management programs), certain operation and maintenance expenses, and depreciation expense related to certain projects. There is no return for cost-recovery expenses.

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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.

		Three Months Ended March 31, 2010									Three Months Ended March 31, 2009


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

Operating revenue		$	1,265		$	894		$	2,159		$	1,204		$	985		$	2,189

Fuel and purchased power			—			689			689			—			739			739
Operation and maintenance			519			194			713			441			217			658
Depreciation, decommissioning and amortization			300			9			309			273			12			285
Property taxes and other			68			—			68			66			—			66

Total operating expenses			887			892			1,779			780			968			1,748

Operating income			378			2			380			424			17			441
Net interest expense and other			(72	)		(2	)		(74	)		(82	)		(5	)		(87	)

Income before income taxes			306			—			306			342			12			354
Income tax expense			129			—			129			121			—			121

Net income			177			—			177			221			12			233
Net income attributable to noncontrolling interest			—			—			—			—			12			12
Dividends on preferred and preference stock not subject to mandatory redemption			13			—			13			13			—			13

Net income available for common stock		$	164		$	—		$	164		$	208		$	—		$	208

Core Earnings³								$	203								$	208
Non-Core Earnings:
	Tax impact of health care legislation								(39	)								—

Total SCE GAAP Earnings								$	164								$	208

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 months ended March 31, 2009 were the following balances related to the Big 4 projects:

(in millions)	Three Months Ended March 31, 2009


Operating revenue	$	143

Fuel		102
Operation and maintenance		21
Depreciation		8

Total operating expenses		131

Net Income	$	12

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 ($22 million for both operating revenue and total expenses) 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

2010 vs. 2009

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $61 million primarily due to the following:

•: $40 million increase due to implementation of the 2009 GRC (effective January 1, 2009) which authorized a 4.25% increase in 2010 authorized revenue.
•: $25 million increase resulting from 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 $78 million including the impact of curtailed spending in the first quarter of 2009 until the 2009 CPUC GRC decision was received in March 2009. The increase in operation and maintenance expense was primarily in the following areas:

•: $30 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 and increases in preventive maintenance work.
•: $20 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.

The first two of the four replacement steam generators were installed in San Onofre Unit 2 in the first quarter of 2010 and the final two are expected to be installed in San Onofre Unit 3 in late 2010. 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.

•

Higher depreciation expense of $27 million primarily resulting from increased capital investments including capitalized software costs.

•

Lower net interest expense and other of $10 million primarily due 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.

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Utility Cost-Recovery Activities

2010 vs. 2009

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 $68 million primarily due to: higher QF power-purchase expense of $130 million primarily due to higher natural gas prices and higher kWh purchases; and higher ISO-related energy costs of $70 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 $65 million primarily due to decreased kWh purchases. Realized losses on economic hedging activities were $24 million in 2010 and $98 million in 2009. Changes in realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than average fixed prices.
•: Lower fuel expense of $16 million primarily due to lower costs at Four Corners (coal) of $10 million resulting from an outage during the first quarter 2010 and lower costs at San Onofre Unit 2 of $5 million resulting from the first quarter 2010 outage described above.

Supplemental Operating Revenue Information

SCE's total consolidated operating revenue was $2.2 billion for both the three months ended March 31, 2010 and 2009, of which $2.0 billion and $1.9 billion were related to retail billed and unbilled revenue (excluding wholesale sales) for March 31, 2010 and 2009, respectively. During the first quarter of 2010, retail billed and unbilled revenue increased $145 million compared to the first quarter of 2009. The increase reflects a rate increase of $182 million and a sales volume decrease of $37 million. The rate increase was due to higher system average rates for the first quarter of 2010 compared to the first quarter of 2009. Effective April 4, 2009, SCE's overall system average rate increased due to the implementation of both revenue allocation and rate design changes authorized in the 2009 GRC and the FERC transmission rate changes authorized in the 2009 FERC rate case. The sales volume decrease was due to the economic downturn. 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).

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 $296 million and $505 million for the three months ended March 31, 2010 and 2009, respectively. Effective January 1, 2010, the CDWR-related rates were decreased primarily to refund CDWR overcollections to customers.

Effective Income Tax Rates

SCE's effective tax rates were 42% and 35% (excluding income attributable to non-controlling interests) for the three months ended March 31, 2010 and 2009, respectively. The increase in the effective tax rate was primarily due to a $39 million non-cash charge recorded in the first quarter of

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2010 to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010, partially offset by higher property-related flow-through tax deductions in 2010.

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 March 31, 2010, SCE had approximately $2.7 billion of available liquidity comprised of cash and equivalents and short-term investments and $2.6 billion available under credit facilities. As of March 31, 2010, SCE's long-term debt, including current maturities of long-term debt, was $7.0 billion.

The following table summarizes the status of SCE's credit facilities at March 31, 2010:

(in millions)	Credit Facilities¹


Commitment	$	2,894
Outstanding borrowings		(180	)
Outstanding letters of credit		(82	)

Amount available	$	2,632

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.

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 March 31, 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. Settlement negotiations on the 2006 – 2008 energy savings and earnings are expected to begin in late May 2010 and 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.

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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 March 31, 2010, SCE's 13-month weighted-average common equity component of total capitalization was 50.5% resulting in the capacity to pay $381 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)	March 31, 2010


Collateral posted as of March 31, 2010¹	$	97
Incremental collateral requirements resulting from a potential downgrade of SCE's credit rating to below investment grade		154

Total posted and potential collateral requirements²	$	251

¹: Collateral posted consisted of $10 million which was offset against net derivative liabilities and $87 million provided to counterparties and other brokers (consisting of $5 million in cash reflected in "Margin and collateral deposits" on the consolidated balance sheets and $82 million in letters of credit).
²: Total posted and potential collateral requirements may increase by an additional $32 million, based on SCE's forward position as of March 31, 2010, due to adverse market price movements over the remaining life of the existing contracts using a 95% confidence level.

In the table above, there was zero collateral posted as of March 31, 2010 related to derivative liabilities, and $16 million of incremental collateral requirements related to derivative liabilities.

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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

	Three Months Ended March 31,

(in millions)	2010			2009

Cash flows provided by operating activities	$	313		$	406
Cash flows provided (used) by financing activities		305			(101	)
Cash flows used by investing activities		(922	)		(739	)
Effect of deconsolidation of variable interest entities		(92	)		—

Net decrease in cash and equivalents	$	(396	)	$	(434	)

Cash Flows Provided by Operating Activities

Cash provided by operating activities decreased $93 million in the first quarter of 2010, compared to the first quarter of 2009 primarily due to a decrease in pre-tax income, the timing of cash receipts and disbursements related to working capital items and income taxes paid in 2010 compared to income tax refunds received in 2009.

Cash Flows Provided (Used) by Financing Activities

Cash provided (used) by financing activities mainly consisted of net repayments of short-term debt and long-term debt issuances (payments).

Cash provided by financing activities for the first quarter of 2010 were $305 million consisting of the following significant events:

•: 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.
•: Borrowed $180 million under SCE's line of credit to fund interim working capital requirements.
•: Repaid $250 million of senior unsecured notes.
•: Paid $100 million in dividends to Edison International.

Cash used by financing activities for the first quarter of 2009 were $101 million consisting of the following significant events:

•: 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 $335 million of borrowings under SCE's line of credit, primarily due to the improvement in economic conditions that occurred during the second half of 2008.
•: 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. SCE continues to hold the bonds which remain 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 were $867 million and $690 million for the three months ended March 31, 2010 and 2009, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $49 million and $42 million for the three months ended March 31, 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."

Contingencies

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

Environmental Remediation

As of March 31, 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. 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 March 31, 2010, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $7.4 billion, compared to a carrying value of $7.0 billion.

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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."

	March 31, 2010						December 31, 2009


(in millions)	Assets			Liabilities			Assets		Liabilities

Electricity options, swaps and forward arrangements	$	—		$	82		$	1	$	25
Natural gas options, swaps and forward arrangements		74			296			86		171
Congestion revenue rights		199			—			217		—
Tolling arrangements¹		—			732			43		402
Netting and collateral		(2	)		(12	)		—		—

Total	$	271		$	1,098		$	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.

(in millions)


Fair value of derivative contracts, net liability at January 1, 2010		$	(251	)
Total realized/unrealized net losses:
	Included in regulatory assets and liabilities¹		(605	)
Purchases and settlements, net			19
Netting and collateral			10

Fair value of derivative contracts, net liability at March 31, 2010		$	(827	)

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 from ratepayers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are deferred and are not recognized as purchased power expense, and therefore do not affect earnings. Realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than average fixed prices. Unrealized gains on economic hedging activities were primarily due to the decrease in forward natural gas prices and declining market conditions related to SCE's new generation contracts.

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 balance sheet. SCE enters

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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 March 31, 2010, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:

	March 31, 2010

(in millions)	Exposure²		Collateral		Net Exposure

S&P Credit Rating¹
A or higher	$	209	$	—	$	209
A-		1		—		1
BBB+		—		—		—
BBB		—		—		—
BBB-		—		—		—
Below investment grade and not rated		—		—		—

Total	$	210	$	—	$	210

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 sheet, except for any related net accounts receivable.

The credit risk exposure set forth in the above table is comprised of $1 million of net account receivables and $209 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

The CAISO comprises 95% 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 in the first quarter of 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 March 31,

(in millions)		2010			2009

Competitive power generation operating revenue		$	652		$	624

Fuel			213			187
Other operation and maintenance			250			239
Depreciation, decommissioning and amortization			59			56
Lease terminations and other			4			21

Total operating expenses			526			503

Operating Income			126			121
Interest and dividend income			20			7
Equity in income from partnerships and unconsolidated subsidiaries – net			18			(2	)
Other income			(1	)		1
Interest expense – net of amounts capitalized			(67	)		(77	)

Income from continuing operations before income taxes			96			50

Income tax expense			25			5

Income from continuing operations			71			45
Income from discontinued operations – net of tax			6			3

Net income			77			48
Less: Net income attributable to noncontrolling interests			—			—

Net income available for common stock		$	77		$	48

Core Earnings¹		$	71		$	56
Non-Core Earnings:
	Lease Terminations²		—			(11	)
	Discontinued Operations		6			3

Total EMG GAAP Earnings		$	77		$	48

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.

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EMG core earnings during the first quarter of 2010 were higher than in the first quarter of 2009 primarily due to the following:

•: $33 million increased income from distributions from the March Point and Doga projects during the first quarter of 2010 without comparable amounts during the first quarter of 2009.
•: $37 million increased energy trading income during the first quarter of 2010 due to congestion and basis trading.

These increases were partially offset by the following:

•: $27 million decreased income from Midwest Generation due to lower average realized energy prices, driven by lower hedge prices. The decrease from lower energy prices was partially offset by lower emission costs and higher capacity prices. The average realized energy price was 17% lower during the first quarter of 2010 as compared to the first quarter of 2009. In addition, Midwest Generation recorded unrealized gains of $15 million during the first quarter of 2009 compared to $2 million in the first quarter of 2010.
•: $17 million decreased income from renewable projects due to low wind, which resulted in a capacity factor decrease despite an availability factor increase. Availability increased as a result of completing the blade remediation program but was partially offset by outages caused by severe winter weather. Liquidated damages totaling $11 million partially offset by availability losses related to blade issues in 2009 and those liquidated damages were not applicable in 2010 as availability losses were not equipment warranty related.
•: $10 million decreased income from leveraged leases following the termination of cross border leases during 2009, which occurred as part of the Global Settlement with the Internal Revenue Service.

Consolidated non-core items for EMG included:

•: An after-tax loss of $11 million in the first quarter of 2009 from termination of two of Edison Capital's cross-border leases.

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 first quarters of 2010 and 2009, together with discussions of the contributions by specific projects and other significant factors affecting these results.

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The following table shows the AOI of EMG's projects:

	Three Months Ended March 31,

(in millions)	2010			2009

Midwest Generation plants	$	87		$	114
Homer City facilities		37			36
Renewable energy projects		10			27
Energy trading		47			10
Big 4 projects		4			6
Sunrise		(4	)		(5	)
Doga		15			—
March Point		17			2
Westside projects		1			3
Leveraged lease income		1			11
Lease termination and other		(3	)		(20	)
Other operating income (expense)		5			(7	)

		217			177
Corporate administrative and general		(38	)		(37	)
Corporate depreciation and amortization		(4	)		(3	)

AOI¹	$	175		$	137

¹: AOI is equal to operating income under GAAP, plus equity in earnings (losses) 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 as reflected on EMG's consolidated statements of income:

		Three Months Ended March 31,

(in millions)		2010		2009

AOI		$	175	$	137
Less:
	Equity in earnings (losses) of unconsolidated affiliates		18		(2	)
	Dividend income from projects		16		2
	Production tax credits		14		16
	Other income, net		1		—

Operating Income		$	126	$	121

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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 March 31,

(in millions)			2010			2009

Operating Revenues			$	379		$	384

Operating Expenses
	Fuel¹			141			123
	Gain on sale of emission allowances²			(1	)		—
	Plant operations			99			96
	Plant operating leases			19			19
	Depreciation and amortization			28			27
	Loss on disposal of assets			1			—
	Administrative and general			5			5

	Total operating expenses			292			270

Operating Income				87			114

AOI			$	87		$	114

Statistics
	Generation (in GWh):
		Energy only contracts		8,212			5,756
		Load requirements services contract		—			886

	Total			8,212			6,642

¹: Included in fuel costs were $4 million and $19 million during the quarters ended March 31, 2010 and 2009, respectively, related to the net cost of emission allowances. Midwest Generation purchased NO_x emission allowances from Homer City at fair market value. Purchases were $0.4 million and $1 million during the quarters ended March 31, 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."
²: Midwest Generation sold excess SO₂ emission allowances to Homer City at fair market value. Sales to Homer City were $4 million during the first quarter of 2010. There were no sales in 2009. These sales reduced operating expenses. Midwest Generation recorded $1 million of intercompany profit during the first quarter of 2010 on emission allowances sold and used by Homer City by March 31, 2010.

AOI from the Midwest Generation plants decreased $27 million in the first quarter of 2010, compared to the first quarter of 2009. The 2010 decrease in AOI was primarily attributable to lower average realized energy prices, driven by lower hedge prices. The decrease was partially offset by lower emission costs and higher capacity prices.

Included in operating revenues were unrealized gains of $7 million and $15 million for the first quarters of 2010 and 2009, respectively. Unrealized gains in 2010 were due to both the 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).

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Unrealized gains in 2009 were primarily due to hedge contracts which are not accounted for as cash flow hedges.

Included in fuel expenses were unrealized losses of $5 million for the three months ended March 31, 2010 due to oil futures contracts which were accounted for as economic hedges. The contracts were entered into in 2009 to hedge a portion of a fuel adjustment provision 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 March 31,

(in millions)		2010		2009

Operating Revenues		$	175	$	165

Operating Expenses
	Fuel¹		70		64
	Plant operations		37		34
	Plant operating leases		25		25
	Depreciation and amortization		5		5
	Administrative and general		1		1

	Total operating expenses		138		129

Operating Income			37		36

AOI		$	37	$	36

Statistics
	Generation (in GWh)		2,954		2,658

¹: Included in fuel costs were $4 million and $7 million during the quarters ended March 31, 2010 and 2009, respectively, related to the net cost of emission allowances. Homer City purchased SO₂ emission allowances from Midwest Generation at fair market value. Purchases were $4 million during the quarter ended March 31, 2010. There were no purchases in 2009. 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 increased $1 million for the first quarter of 2010, compared to 2009. AOI in 2010 as compared to 2009 includes an increase in realized gross margin due to an increase in capacity revenues and higher generation, partially offset by a 12% decline in average realized energy prices.

Included in operating revenues were unrealized losses from hedge activities of $2 million and none for the first quarters of 2010 and 2009, respectively. Unrealized losses in 2010 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

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

Non-GAAP Disclosures—Fossil-Fueled Facilities

Adjusted Operating Income

AOI is equal to operating income 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 March 31,

(in millions)		2010			2009

Operating Revenues		$	30		$	44
Production Tax Credits			14			16

			44			60

Operating Expenses
	Plant operations		12			13
	Depreciation and amortization		21			20
	Administrative and general		1			1

	Total operating expenses		34			34
Equity in earnings (losses) of unconsolidated affiliates			(1	)		—
Other Income			1			1

AOI¹		$	10		$	27

Statistics
	Generation (in GWh)		843			820

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 March 31,

(in millions)		2010			2009

AOI		$	10		$	27
Less:
	Equity in earnings (losses) of unconsolidated affiliates		(1	)		—
	Production tax credits		14			16
	Other income		1			1

Operating Income (Loss)		$	(4	)	$	10

AOI from renewable energy projects decreased $17 million in the first quarter of 2010, compared to the first quarter of 2009. The 2010 decrease in AOI was primarily attributable to low wind and adverse weather conditions. In addition, the expiration in 2009 of production tax credit terms for some renewable energy projects reduced production tax revenue for the first quarter of 2010. AOI in the first quarter of 2009 included $11 million of liquidated damages received with respect to availability guarantees provided by a wind turbine supplier, which compensated EMG for lower generation. The first quarter of 2010 did not include liquidated damages for equipment warranty related items given completion of the blade remediation program.

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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, 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 $37 million for the first quarter of 2010, compared to the first quarter of 2009. The 2010 increase in AOI from energy trading activities was 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 in the first quarter of 2010 compared to the first quarter of 2009 due to declines in the lease portfolio caused by termination of the cross-border leases during the first half of 2009 and the sale of another lease investment in the second quarter of 2009.

Adjusted Operating Income from Lease Termination and Other

Results in the first quarter of 2009 included losses of $18 million on the termination of two cross-border leases.

Adjusted Operating Income from Unconsolidated Affiliates

Doga

AOI from the Doga project increased $15 million for the first quarter of 2010, compared to the first quarter of 2009. 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 $15 million for the first quarter of 2010, compared to the first quarter 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 March 31,

(in millions)			2010			2009

Interest income			$	3		$	6

Interest expense:
	EME debt		$	(60	)	$	(68	)
	Non-recourse debt:
		Midwest Generation		(1	)		(3	)
		EME Funding		—			(2	)
		EME CP Holding Co.		(1	)		(1	)
		Viento Funding II, Inc.		(4	)		—
		Other projects		(1	)		(3	)

			$	(67	)	$	(77	)

EMG's interest expense decreased $10 million for the first quarter of 2010, compared to the first quarter of 2009. The 2010 decrease was primarily due to lower debt balances under EME's and Midwest Generation's credit facilities and debt repayments at EME Funding in 2010, compared to 2009. Capitalized interest for projects under construction increased $5 million for the first quarter of 2010, compared to the first quarter of 2009.

Income Taxes

EMG's effective tax rates were 26% and 11% for the three months ended March 31, 2010 and 2009, respectively. The effective tax rate for the first quarter of 2010 was impacted by higher pretax income in relation to the level of production tax credits. Production tax credits for wind projects of $14 million and $16 million were recognized for the three months ended March 31, 2010 and 2009, respectively. The effective tax rate for the first quarter of 2009 was impacted by the termination of two of Edison Capital's cross border leases which were related to the Global Settlement that was subsequently completed.

Results of Discontinued Operations

Income from discontinued operations, net of tax, increased $3 million for the first quarter of 2010, compared to the first quarter of 2009. The 2010 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.

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

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consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities:

		Three Months Ended March 31,

(in millions)		2010			2009

Midwest Generation plants
	Non-qualifying hedges	$	(2	)	$	16
	Ineffective portion of cash flow hedges		4			(1	)
Homer City facilities
	Non-qualifying hedges		—			(1	)
	Ineffective portion of cash flow hedges		(2	)		1

Total unrealized gains		$	—		$	15

At March 31, 2010, cumulative unrealized gains of $45 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($29 million for the remainder of 2010, $13 million for 2011, and $3 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 MD&A.

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LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

At March 31, 2010, EMG and its subsidiaries had consolidated cash and cash equivalents of $1.3 billion and a total of $962 million of available borrowing capacity under their credit facilities. EMG's consolidated debt at March 31, 2010 was $4.1 billion, of which $45 million was current. In addition, EMG's subsidiaries had $3.2 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 25 years.

The following table summarizes the status of the EME and Midwest Generation credit facilities at March 31, 2010:

(in millions)	EME			Midwest Generation


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

		564			500
Outstanding borrowings		—			—
Outstanding letters of credit		(99	)		(3	)

Amount available	$	465		$	497

As a result of the recent credit ratings actions 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 $905 million (excluding the Mitsubishi disputed amount) to be funded with a combination of project-level financing, U.S. Treasury grants, cash on hand, and cash flow from operations. EMG has secured financing of $206 million through vendor financing and $160 million through project financing, of which $88 million was available under the loan, and received funds from U.S. Treasury grants totaling $92 million in April 2010. EMG intends to file for U.S. Treasury grants for its renewable energy projects in construction and pending construction.

Global Settlement

As discussed in the year-ended 2009 MD&A under the heading, "Edison International Parent and Other—Liquidity and Capital Resources—Historical Cash Flow," Edison International and the IRS finalized the terms of a Global Settlement 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. In April 2010, Edison International remitted a $253 million deposit to the IRS related to the Global Settlement. The deposit is related to Edison Capital's tax liability arising from the Global Settlement and was funded by Edison Capital pursuant to Edison International's tax-allocation agreement with EMG.

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Capital Investment Plan

At March 31, 2010, the estimated capital expenditures through 2012 by EMG's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

(in millions)		April through December 2010		2011		2012


Midwest Generation Plants
	Plant capital expenditures	$	56	$	79	$	10
	Environmental expenditures¹		88		75		—
Homer City Facilities
	Plant capital expenditures		16		52		24
	Environmental expenditures		1		3		22
Renewable Projects
	Capital and construction expenditures²		646		—		—
	Turbine commitments³		82		4		—
Other capital expenditures			16		17		9

Total		$	905	$	230	$	65

¹: Environmental expenditures include primarily expenditures related to SNCR equipment. Additional expenditures, which may be material, are anticipated; however, the amounts and timing have not been determined. For additional discussion, refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K.
²: Includes projects under construction where project financing has been secured. The amounts secured include $206 million and $135 million related to construction financings.
³: 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. Midwest Generation continues to review all technology and unit shutdown combinations, including interim and alternative compliance solutions. Expenditures, in addition to those included on the preceding table, are anticipated and could be material; however, 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,

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which EMG estimates to be an additional $75 million to $120 million based on typical project costs. The pace of further 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, and it may be affected by future decisions about capital expenditures for environmental compliance by its coal fleet. 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

	Three Months Ended March 31,

(in millions)	2010			2009

Operating cash flow from continuing operations	$	284		$	281
Operating cash flow from discontinued operations		6			3

Cash flows provided by operating activities		290			284
Cash flows used by financing activities		(55	)		(16	)
Cash flows provided (used) by investing activities		(100	)		46
Effect of consolidation of variable interest entity		5			—
Effect of deconsolidation of variable interest entity		(4	)		—

Net increase (decrease) in cash and cash equivalents	$	136		$	314

Consolidated Cash Flows Provided by Operating Activities

Cash provided by operating activities from continuing operations increased in the first quarter of 2010, compared to the first quarter of 2009. The 2010 increase was primarily attributable to higher net income and changes in the timing of cash receipts and disbursements related to working capital items.

Consolidated Cash Flows Used by Financing Activities

Cash used by financing activities from continuing operations decreased $39 million in the first quarter of 2010, compared to the first quarter of 2009. The 2010 decrease was primarily attributable to an $89 million repayment of long-term debt at Edison Funding Company, partially offset by borrowings of $47 million under the Cedro Hill wind project's construction loan issued in March 2010. For further project financing details, see "Edison International Notes to Consolidated Financial Statements Note 3. Liabilities and Lines of Credit—Long-Term Debt."

Consolidated Cash Flows Provided (Used) by Investing Activities

Cash used in investing activities from continuing operations decreased $146 million in the first quarter of 2010, compared to the first quarter of 2009. The 2010 decrease was primarily due to the termination of cross-border leases in which Edison Capital received net proceeds of $121 million in the first quarter of 2009. This decrease was partially offset by higher expenditures for renewable energy projects in 2010, compared to 2009.

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Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT are as follows:

	Moody's Rating	S&P Rating	Fitch Rating


EME¹	B2	B-	B-
Midwest Generation²	Ba1	B+	BB
EMMT	Not Rated	B-	Not Rated

¹: Senior unsecured rating.
²: First priority senior secured rating.

On March 12, 2010, Fitch lowered the credit ratings of EME to B- from BB- and Midwest Generation to BB from BBB-. On April 6, 2010, Moody's placed the credit ratings of EME and Midwest Generation under review for possible downgrade. On April 12, 2010, S&P lowered the credit ratings of EME and EMMT to B- from B and Midwest Generation to B+ from BB-. The S&P and Fitch ratings are on negative outlook. 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 March 31, 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 March 31, 2010 could increase by approximately $161 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 EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—Debt Covenants and Dividend Restrictions."

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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 March 31, 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

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

	March 31, 2010		December 31, 2009

Ratio		1.99		1.72
Covenant threshold (not less than)		1.20		1.20

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




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

Key Ratios of EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at March 31, 2010 or for the 12 months ended March 31, 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	3.10 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 March 31, 2010, the maximum permissible sale or disposition of EME assets was $824 million.

Contractual Obligations and Contingencies

Fuel Supply Contracts and Coal Transportation Agreements

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

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

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Environmental Matters and Regulations

For a discussion of Edison International's environmental matters, refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K.

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 quarterly average historical market prices for energy per megawatt-hour at the locations indicated for the first quarters of 2010 and 2009:

		24-Hour Average Historical Market Prices¹

		2010		2009

Midwest Generation plants
	Northern Illinois Hub	$	34.53	$	34.06
Homer City facilities
	PJM West Hub		44.53		49.09
	Homer City Busbar		39.33		44.72

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 March 31, 2010:

		24-Hour Forward Energy Prices¹

		Northern Illinois Hub		PJM West Hub

2010
	April	$	25.95	$	34.77
	May		25.62		34.14
	June		27.86		36.92
	July		31.15		42.51
	August		32.22		43.71
	September		27.05		36.30
	October		25.04		35.88
	November		28.24		37.21
	December		30.43		41.33
2011 calendar "strip"²			30.85		42.04

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) as of March 31, 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/ MWh¹		MWh (in thousands)		Average price/ MWh¹		MWh (in thousands)		Average price/ MWh¹

Midwest Generation plants
	Northern Illinois and AEP/Dayton Hubs		14,354	$	42.97		9,708	$	41.55		1,632	$	41.15
Homer City facilities²
	PJM West Hub		2,676		79.19		2,224		47.14		1,182		44.16

Total			17,030				11,932				2,814

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 March 31, 2010, EMMT had entered into 2.5 BCF of natural gas futures contracts (equivalent to approximately 408 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 March 31, 2010:

									RPM Capacity Sold in Base Residual Auction				Other Capacity Sales, Net of Purchases²


		Installed Capacity MW		Unsold Capacity¹ MW			Capacity Sold MW		MW		Price per MW-day		MW			Average Price per MW-day		Aggregate Average Price per MW-day

April 1, 2010 to May 31, 2010
	Midwest Generation		5,776		(878	)		4,898		5,329	$	102.04		(431	)	$	99.23	$	102.29
	Homer City		1,884		(206	)		1,678		1,670		191.32		8			191.32		191.32
June 1, 2010 to May 31, 2011
	Midwest Generation		5,477		(548	)		4,929		4,929		174.29		—			—		174.29
	Homer City		1,884		(161	)		1,723		1,813		174.29		(90	)		50.00		180.78
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

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.

Revenues from the sale of capacity from Midwest Generation and Homer City beyond the periods set forth above will depend upon the amount of capacity available and future market prices either in PJM or nearby markets if EMG has an opportunity to capture a higher value associated with those markets. Under PJM's RPM system, the market price for capacity is generally determined by aggregate market-based supply conditions and an administratively set aggregate demand curve. Among the factors influencing the supply of capacity in any particular market are plant forced outage rates, plant closings, plant delistings (due to plants being removed as capacity resources and/or to export capacity to other markets), capacity imports from other markets, demand side management activities and the cost of new entry.

Basis Risk

During the three months ended March 31, 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 12% and 9%, respectively. During the three months ended March 31, 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 16% and 1%, respectively, during the three months ended March 31, 2009.

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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 March 31, 2010 for the remainder of 2010 and the following three years:

	Amount of Coal Under Contract in Millions of Equivalent Tons¹

	April through December 2010		2011		2012		2013

Midwest Generation plants		13.9		11.7		9.8		—
Homer City facilities		3.5		3.9		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.

EMG is subject to price risk for purchases of coal that are not under contract. Prices of 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 SO₂ per MMBtu sulfur content) increased to a price of $62.75 per ton at April 1, 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 SO₂ 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 $12.35 per ton at April 1, 2010, compared to a price of $9.25 per ton at December 31, 2009, as reported by the Energy Information Administration.

EMG has contractual agreements 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 SO₂ allowances increased to $77 per ton during the first quarter of 2010 from $65 per ton in 2009. The average purchase price of annual NO_x allowances decreased to $992 per ton during the first quarter of 2010 from $1,431 per ton in 2009. Based on broker's quotes and information from public sources, the spot price for SO₂ allowances and annual NO_x allowances was $55 per ton and $450 per ton, respectively, at March 31, 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.

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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 March 31, 2010, the balance sheet exposure as described above, broken down by the credit ratings of EMG's counterparties, was as follows:

		March 31, 2010

(in millions)		Exposure²		Collateral			Net Exposure

Credit Rating¹
	A or higher	$	261	$	(108	)	$	153
	A-		46		—			46
	BBB+		42		—			42
	BBB		49		—			49
	BBB-		19		—			19
	Below investment grade		100		(99	)		1

Total		$	517	$	(207	)	$	310

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 sheet, except for any related accounts receivable.

The credit risk exposure set forth in the above table is comprised of $105 million of net accounts receivable and payables and $412 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 $124 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 69% of EMG's consolidated operating revenues for the three months ended March 31, 2010. Moody's rates PJM's debt Aa3. PJM, an ISO with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At March 31, 2010, EMG's account receivable due from PJM was $42 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.

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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 values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EMG's consolidated long-term obligations (including current portion) was $3.1 billion at March 31, 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 losses from continuing operations were $5 million and $6 million for the three months ended March 31, 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

	Three Months Ended March 31,

(in millions)	2010			2009

Cash flows used by operating activities	$	(4	)	$	(4	)
Cash flows provided (used) by financing activities		9			(250	)
Net cash provided by investing activities		—			2

Net increase (decrease) in cash and equivalents	$	5		$	(252	)

Cash Flows Provided (Used) by Financing Activities

Financing activities for the first quarter of 2010 were as follows:

•: Paid $103 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.
•: Received $100 million of dividends payments from SCE.
•: Borrowed $12 million under Edison International's line of credit to fund interim working capital requirements.

Financing activities for the first quarter of 2009 were as follows:

•: Paid $101 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 $250 million of short-term debt, primarily due to the improvement in economic conditions that occurred during the second half of 2008.
•: 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."

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."

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 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.

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."

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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


January 1, 2010 to January 31, 2010	579,671	$	34.36	—	—
February 1, 2010 to February 28, 2010	340,343		33.33	—	—
March 1, 2010 to March 31, 2010	422,756		34.13	—	—

Total	1,342,770	$	34.03	—	—

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 2010 Executive Annual Incentive Program
10.2		Edison International 2010 Long-Term Incentives Terms and Conditions
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 March 31, 2010, filed on May 7, 2010, formatted in XBRL: (i) the Consolidated Statements of Income; (ii) the Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; and (v) the Notes to the Consolidated Financial Statements tagged as blocks of text

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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: May 7, 2010