EDISON INTERNATIONAL (Form: 10-Q, Received: 05/02/2011 08:55:45)

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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, 2011
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. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.


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 April 28, 2011

Common Stock, no par value		325,811,206

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GLOSSARY			v
PART I. FINANCIAL INFORMATION
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. Consolidated Statements of Changes in Equity		9
	Note 3. Variable Interest Entities		9
	Note 4. Fair Value Measurements		11
	Note 5. Debt and Credit Agreements		16
	Note 6. Derivative Instruments and Hedging Activities		16
	Note 7. Income Taxes		23
	Note 8. Compensation and Benefit Plans		24
	Note 9. Commitments and Contingencies		26
	Note 10. Regulatory and Environmental Developments		32
	Note 11. Accumulated Other Comprehensive Income (Loss)		33
	Note 12. Supplemental Cash Flows Information		34
	Note 13. Preferred and Preference Stock of Utility		34
	Note 14. Regulatory Assets and Liabilities		34
	Note 15. Other Investments		35
	Note 16. Other Income and Expenses		36
	Note 17. Business Segments		36
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			38
FORWARD-LOOKING STATEMENTS			38
EDISON INTERNATIONAL MANAGEMENT OVERVIEW
	Highlights of Operating Results		39
	Management Overview of SCE		40
		*Capital Program*	40
		*2012 CPUC General Rate Case*	40
		*Nuclear Industry and Regulatory Response to Events in Japan*	40
	Management Overview of EMG		41
		*Midwest Generation Environmental Compliance Plans and Costs*	41
		*Homer City Outage*	41

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	Environmental Regulation Developments			42
SOUTHERN CALIFORNIA EDISON COMPANY
RESULTS OF OPERATIONS				43
	Electric Utility Results of Operations			43
		*Utility Earning Activities*		44
			2011 vs. 2010	44
		*Utility Cost-Recovery Activities*		44
			2011 vs. 2010	44
		*Supplemental Operating Revenue Information*		44
		*Income Taxes*		45
LIQUIDITY AND CAPITAL RESOURCES				45
	Available Liquidity			45
		*Debt Covenant*		46
	Dividend Restrictions			46
	Margin and Collateral Deposits			46
		*Derivative Instruments and Power Procurement Contracts*		46
		*Workers Compensation Self-Insurance Fund*		46
	Historical Consolidated Cash Flows			46
		*Condensed Consolidated Statement of Cash Flows*		47
			Net Cash Provided by Operating Activities	47
			Net Cash Provided by Financing Activities	47
			Net Cash Used by Investing Activities	47
	Contractual Obligations and Contingencies			48
		*Contractual Obligations*		48
		*Contingencies*		48
			Environmental Remediation	48
MARKET RISK EXPOSURES				48
	Commodity Price Risk			48
	Credit Risk			48
EDISON MISSION GROUP
RESULTS OF OPERATIONS				50
	Results of Continuing Operations			50
		*Adjusted Operating Income ("AOI") —Overview*		51
		*Adjusted Operating Income from Consolidated Operations*		52
			Midwest Generation Plants	52
			Homer City	53
			Seasonality—Coal Plants	53
			Renewable Energy Projects	54
			Energy Trading	54
		*Adjusted Operating Income from Unconsolidated Affiliates*		55
		*Interest Expense*		55

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		*Income Taxes*		55
	Results of Discontinued Operations			55
LIQUIDITY AND CAPITAL RESOURCES				56
	Available Liquidity			56
	Capital Investment Plan			57
		*Environmental Capital Expenditures*		57
		*Non-Environmental Capital Expenditures*		57
		*Future Projects*		58
	Historical Segment Cash Flows			58
		*Condensed Statement of Cash Flows*		58
			Net Cash Provided by Operating Activities	58
			Net Cash Provided by Financing Activities	59
			Net Cash Provided by Investing Activities	59
	Credit Ratings			59
		*Overview*		59
		*Credit Rating of EMMT*		59
	Margin, Collateral Deposits and Other Credit Support for Energy Contracts			59
	Debt Covenants and Dividend Restrictions			60
		*Credit Facility Financial Ratios*		60
		*Key Ratios of EMG's Principal Subsidiaries Affecting Dividends*		60
		*EMG's Senior Notes and Guaranty of Powerton-Joliet Leases*		60
	Contractual Obligations and Contingencies			61
		*Fuel Supply Contracts*		61
		*Midwest Generation New Source Review Lawsuit*		61
		*Homer City New Source Review Lawsuit*		61
	Off-Balance Sheet Transactions			61
MARKET RISK EXPOSURES				61
	Derivative Instruments			61
		*Unrealized Gains and Losses*		61
		*Fair Value Disclosures*		61
	Commodity Price Risk			62
		*Energy Price Risk Affecting Sales from the Coal Plants*		62
		*Capacity Price Risk*		63
		*Basis Risk*		64
		*Coal and Transportation Price Risk*		64
		*Emission Allowances Price Risk*		64
	Credit Risk			65
	Interest Rate Risk			66

iii

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EDISON INTERNATIONAL PARENT AND OTHER
RESULTS OF OPERATIONS				67
LIQUIDITY AND CAPITAL RESOURCES				67
	Historical Cash Flows			67
		*Condensed Statement of Cash Flows*		67
			Net Cash Used by Operating Activities	67
			Net Cash Provided (Used) by Financing Activities	68
EDISON INTERNATIONAL (CONSOLIDATED)
LIQUIDITY AND CAPITAL RESOURCES				69
	Contractual Obligations			69
CRITICAL ACCOUNTING ESTIMATES AND POLICIES				69
NEW ACCOUNTING GUIDANCE				69
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				69
ITEM 4. CONTROLS AND PROCEDURES				69
	Disclosure Controls and Procedures			69
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS				69
	California Coastal Commission Potential Environmental Proceeding			69
	Midwest Generation New Source Review Lawsuit			70
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS				70
	Purchases of Equity Securities by the Issuer and Affiliated Purchasers			70
ITEM 6. EXHIBITS				70
SIGNATURE				71

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GLOSSARY

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


2010 Form 10-K		Edison International's Annual Report on Form 10-K for the year-ended December 31, 2010
2010 Tax Relief Act		Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
AFUDC		allowance for funds used during construction
Ambit project		American Bituminous Power Partners, L.P.
AOI		Adjusted Operating Income (Loss)
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
coal plants		Midwest Generation coal plants and Homer City plant
CPS		Combined Pollutant Standard
CPUC		California Public Utilities Commission
CRRs		congestion revenue rights
DOE		U.S. Department of Energy
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
FGIC		Financial Guarantee Insurance Company
FIP(s)		federal implementation plan(s)
Four Corners		coal fueled electric generating facility located in Farmington, New Mexico in which SCE holds a 48% ownership interest
GAAP		generally accepted accounting principles
GHG		greenhouse gas
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 and related matters with state tax authorities.
GRC		general rate case
GWh		gigawatt-hours
HAPs		Hazardous Air Pollutants
Homer City		EME Homer City Generation L.P., a Pennsylvania limited partnership that leases and operates three coal-fired electric generating units and related facilities located in Indiana County, Pennsylvania

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Illinois EPA		Illinois Environmental Protection Agency
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
Midwest Generation		Midwest Generation, LLC
Midwest Generation plants		EME's power plants (fossil fuel) located in Illinois
MMBtu		million British thermal units
Mohave		two coal fueled electric generating facilities that no longer operate located in Clark County, Nevada in which SCE holds a 56% ownership interest
Moody's		Moody's Investors Service
MRTU		Market Redesign and Technology Upgrade
MW		megawatts
MWh		megawatt-hours
NAAQS		national ambient air quality standards
NAPP		Northern Appalachian
NERC		North American Electric Reliability Corporation
Ninth Circuit		U.S. Court of Appeals for the Ninth Circuit
NOV		notice of violation
NO _x		nitrogen oxide
NRC		Nuclear Regulatory Commission
NSR		New Source Review
NYISO		New York Independent System Operator
PADEP		Pennsylvania Department of Environmental Protection
Palo Verde		large pressurized water nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest
PBOP(s)		postretirement benefits other than pension(s)
PBR		performance-based ratemaking
PG&E		Pacific Gas & Electric Company
PJM		PJM Interconnection, LLC
PRB		Powder River Basin
PSD		Prevention of Significant Deterioration
QF(s)		qualifying facility(ies)
ROE		return on equity
RPM		Reliability Pricing Model
RTO(s)		Regional Transmission Organization(s)
S&P		Standard & Poor's Ratings Services
San Onofre		large pressurized water nuclear electric generating facility located in south San Clemente, California in which SCE holds a 78.21% ownership interest
SCE		Southern California Edison Company
SNCR		selective non-catalytic reduction
SDG&E		San Diego Gas & Electric
SEC		U.S. Securities and Exchange Commission
SIP(s)		state implementation plan(s)
SO ₂		sulfur dioxide
US EPA		U.S. Environmental Protection Agency
VIE(s)		variable interest entity(ies)
year-ended 2010 MD&A		Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in the 2010 Form 10-K

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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, unaudited)	2011			2010

Electric utility	$	2,230		$	2,159
Competitive power generation		552			652
Other		—			(1	)

Total operating revenue		2,782			2,810

Fuel		258			295
Purchased power		508			608
Operations and maintenance		1,149			1,037
Depreciation, decommissioning and amortization		417			369
Lease terminations and other		—			3

Total operating expenses		2,332			2,312

Operating income		450			498
Interest and dividend income		4			19
Equity in income (loss) from unconsolidated affiliates – net		(5	)		18
Other income		41			34
Interest expense – net of amounts capitalized		(196	)		(168	)
Other expenses		(13	)		(8	)

Income from continuing operations before income taxes		281			393
Income tax expense		65			150

Income from continuing operations		216			243
Income (loss) from discontinued operations – net of tax		(2	)		6

Net income		214			249
Dividends on preferred and preference stock of utility		14			13

Net income attributable to Edison International common shareholders	$	200		$	236

Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	$	202		$	230
Income (loss) from discontinued operations, net of tax		(2	)		6

Net income attributable to Edison International common shareholders	$	200		$	236

Basic earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding		326			326
Continuing operations	$	0.62		$	0.70
Discontinued operations		(0.01	)		0.02

Total	$	0.61		$	0.72

Diluted earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities		328			328
Continuing operations	$	0.62		$	0.70
Discontinued operations		(0.01	)		0.02

Total	$	0.61		$	0.72
Dividends declared per common share	$	0.320		$	0.315

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, unaudited)			2011			2010

Net income			$	214		$	249
Other comprehensive income (loss), 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		3			(8	)
		Prior service credit arising during the period		—			2
		Amortization of prior service credit		—			(2	)
	Unrealized gain (loss) on derivatives qualified as cash flow hedges:
		Unrealized holding gain arising during the period, net of income tax expense of $4 and $62 for 2011 and 2010, respectively		6			95
		Reclassification adjustments included in net income, net of income tax benefit of $6 and $14 for 2011 and 2010, respectively		(10	)		(20	)

Other comprehensive income (loss)				(1	)		79

Comprehensive income				213			328
Less: Comprehensive income attributable to noncontrolling interests				14			13

Comprehensive income attributable to Edison International			$	199		$	315

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

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Consolidated Balance Sheets	Edison International
(in millions, unaudited)	March 31, 2011		December 31, 2010

ASSETS
Cash and cash equivalents	$	1,298	$	1,389
Receivables, less allowances of $87 and $85 for uncollectible accounts at respective dates		782		931
Accrued unbilled revenue		410		442
Inventory		586		568
Prepaid taxes		533		390
Derivative assets		115		133
Restricted cash		10		2
Margin and collateral deposits		50		65
Regulatory assets		407		378
Other current assets		145		124

Total current assets		4,336		4,422

Nuclear decommissioning trusts		3,619		3,480
Investments in unconsolidated affiliates		544		559
Other investments		232		223

Total investments		4,395		4,262

Utility property, plant and equipment, less accumulated depreciation of $6,488 and $6,319 at respective dates		25,276		24,778
Competitive power generation and other property, plant and equipment, less accumulated depreciation of $1,940 and $1,865 at respective dates		5,437		5,406

Total property, plant and equipment		30,713		30,184

Derivative assets		355		437
Restricted deposits		40		47
Rent payments in excess of levelized rent expense under plant operating leases		1,219		1,187
Regulatory assets		4,450		4,347
Other long-term assets		653		644

Total long-term assets		6,717		6,662




Total assets	$	46,161	$	45,530

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

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Edison International
Consolidated Balance Sheets
(in millions, except share amounts, unaudited)	March 31, 2011			December 31, 2010

LIABILITIES AND EQUITY
Short-term debt	$	334		$	115
Current portion of long-term debt		53			48
Accounts payable		1,059			1,362
Accrued taxes		54			52
Accrued interest		221			205
Customer deposits		211			217
Derivative liabilities		222			217
Regulatory liabilities		778			738
Other current liabilities		761			998

Total current liabilities		3,693			3,952

Long-term debt		12,522			12,371

Deferred income taxes		5,908			5,625
Deferred investment tax credits		120			122
Customer advances		112			112
Derivative liabilities		476			468
Pensions and benefits		2,282			2,260
Asset retirement obligations		2,576			2,561
Regulatory liabilities		4,733			4,524
Other deferred credits and other long-term liabilities		2,030			2,041

Total deferred credits and other liabilities		18,237			17,713

Total liabilities		34,452			34,036

Commitments and contingencies (Note 9)
Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued and outstanding at each date)		2,340			2,331
Accumulated other comprehensive loss		(77	)		(76	)
Retained earnings		8,413			8,328

Total Edison International's common shareholders' equity		10,676			10,583

Preferred and preference stock of utility		1,030			907
Other noncontrolling interests		3			4

Total noncontrolling interests		1,033			911
Total equity		11,709			11,494

Total liabilities and equity	$	46,161		$	45,530

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, unaudited)		2011			2010

Cash flows from operating activities:
Net income		$	214		$	249
Less: Income (loss) from discontinued operations			(2	)		6

Income from continuing operations			216			243
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization			417			369
Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)			41			38
Other amortization			37			24
Lease terminations and other			—			3
Stock-based compensation			7			7
Equity in income (loss) from unconsolidated affiliates – net			5			(18	)
Distributions and dividends from unconsolidated entities			5			22
Deferred income taxes and investment tax credits			226			218
Income from leveraged leases			(1	)		(1	)
Changes in operating assets and liabilities:
	Receivables		128			150
	Inventory		(18	)		(2	)
	Margin and collateral deposits – net of collateral received		15			(6	)
	Prepaid taxes		(143	)		(104	)
	Other current assets		(6	)		(47	)
	Rent payments in excess of levelized rent expense		(32	)		(45	)
	Accounts payable		(49	)		(138	)
	Accrued taxes		1			(6	)
	Other current liabilities		(207	)		(182	)
	Derivative assets and liabilities – net		106			695
	Regulatory assets and liabilities – net		(42	)		(636	)
	Other assets		(7	)		(11	)
	Other liabilities		21			20
Operating cash flows from discontinued operations			(2	)		6

Net cash provided by operating activities			718			599

Cash flows from financing activities:
Long-term debt issued			82			541
Long-term debt issuance costs			(1	)		(14	)
Long-term debt repaid			(9	)		(343	)
Preference stock issued			123			—
Short-term debt financing – net			294			192
Settlements of stock-based compensation – net			(7	)		(1	)
Dividends and distributions to noncontrolling interests			(13	)		(13	)
Dividends paid			(104	)		(103	)

Net cash provided by financing activities		$	365		$	259

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

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Edison International
Consolidated Statements of Cash Flows
	Three months ended March 31,
(in millions, unaudited)	2011			2010

Cash flows from investing activities:
Capital expenditures	$	(1,133	)	$	(951	)
Proceeds from sale of nuclear decommissioning trust investments		622			286
Purchases of nuclear decommissioning trust investments and other		(669	)		(335	)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment		5			32
Investments in other assets		1			(54	)
Effect of consolidation and deconsolidation of variable interest entities		—			(91	)

Net cash used by investing activities		(1,174	)		(1,113	)

Net decrease in cash and cash equivalents		(91	)		(255	)
Cash and cash equivalents, beginning of period		1,389			1,673

Cash and cash equivalents, end of period	$	1,298		$	1,418

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1. Summary of Significant Accounting Policies

Edison International has two business segments for financial reporting purposes: an electric utility operation segment (SCE) and a competitive power generation segment (EMG). SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to an approximately 50,000-square-mile area of southern California. EMG is the holding company for its principal wholly owned subsidiary, EME. EME is a holding company with subsidiaries and affiliates engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also engages in hedging and energy trading activities in competitive power markets through its Edison Mission Marketing & Trading, Inc. ("EMMT") subsidiary.

Basis of Presentation

Edison International's significant accounting policies were described in Note 1 of "Edison International Notes to Consolidated Financial Statements" included in the 2010 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, 2011, discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2010 Form 10-K.

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, 2011 are not necessarily indicative of the operating results for the full year.

The December 31, 2010 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.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $1.0 billion and $1.1 billion at March 31, 2011 and December 31, 2010, respectively. Generally, the carrying value of cash equivalents equals the fair value, as all investments have maturities of three months or less.

Edison International temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. Edison International reclassified $207 million and $197 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at March 31, 2011 and December 31, 2010, respectively.

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 consisted of the following:

(in millions)	March 31, 2011		December 31, 2010


Coal, gas, fuel oil and other raw materials	$	204	$	184
Spare parts, materials and supplies		382		384

Total inventory	$	586	$	568

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. EPS attributable to Edison International common shareholders was computed as follows:

	Three months ended March 31,

(in millions)	2011		2010

Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	202	$	230
Participating securities dividends		—		(1	)

Income from continuing operations available to common shareholders	$	202	$	229
Weighted average common shares outstanding		326		326

Basic earnings per share – continuing operations	$	0.62	$	0.70

Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	202	$	229
Income impact of assumed conversions		1		1

Income from continuing operations available to common shareholders and assumed conversions	$	203	$	230
Weighted average common shares outstanding		326		326
Incremental shares from assumed conversions		2		2

Adjusted weighted average shares – diluted		328		328
Diluted earnings per share – continuing operations	$	0.62	$	0.70

Stock-based compensation awards to purchase 8,980,322 and 5,998,238 shares of common stock were outstanding for the three months ended March 31, 2011 and 2010, respectively, 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.

New Accounting Guidance

Accounting Guidance Adopted in 2011

Revenue—Multiple-Deliverables

In October 2009, the Financial Accounting Standards Board (FASB) issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenues based on those separate deliverables. This update also requires additional disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is required to be applied prospectively to new or significantly modified revenue arrangements. Edison International adopted this guidance effective January 1, 2011. The adoption of this accounting standards update did not have a material impact on Edison International's consolidated results of operations, financial position or cash flows.

Fair Value Measurements and Disclosures

The FASB issued an accounting standards update modifying the disclosure requirements related to fair value measurements. Under these requirements, purchases and settlements for Level 3 fair value measurements are presented on a gross basis, rather than net. Edison International adopted this guidance effective January 1, 2011.

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Note 2. Consolidated Statements of Changes in Equity

The following table provides the changes in equity for the three months ended March 31, 2011.

	Equity Attributable to Edison International											Noncontrolling Interests

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

Balance at December 31, 2010	$	2,331	$	(76	)	$	8,328		$	10,583		$	4		$	907		$	11,494

Net income (loss)		—		—			200			200			—			14			214
Other comprehensive loss		—		(1	)		—			(1	)		—			—			(1	)
Common stock dividends declared ($0.32 per share)		—		—			(104	)		(104	)		—			—			(104	)
Dividends, distributions to noncontrolling interests and other		—		—			—			—			(1	)		(14	)		(15	)
Stock-based compensation and other		2		—			(9	)		(7	)		—			—			(7	)
Noncash stock-based compensation and other		7		—			(2	)		5			—			—			5
Issuance of preference stock		—		—			—			—			—			123			123

Balance at March 31, 2011	$	2,340	$	(77	)	$	8,413		$	10,676		$	3		$	1,030		$	11,709

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

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 and other		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

Note 3. Variable Interest Entities

A variable interest entity ("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 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.

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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.

Categories of Variable Interest Entities

Projects or Entities that are Consolidated

At March 31, 2011 and December 31, 2010, EMG consolidated 13 wind projects with a total generating capacity of 500 MW that have minority interests held by others. EMG also had a 50% partnership interest in the American Bituminous Power Partners, L.P. project, commonly referred to as the Ambit project.

The following table presents summarized financial information of the projects that were consolidated by EMG:

(in millions)		March 31, 2011		December 31, 2010


Current assets		$	36	$	26
Net property, plant and equipment			726		739
Other long-term assets			5		6

	Total assets	$	767	$	771

Current liabilities		$	23	$	25
Long-term debt net of current maturities			70		71
Deferred revenues			72		71
Other long-term liabilities			21		21

	Total liabilities	$	186	$	188

Noncontrolling interests		$	4	$	4

Assets serving as collateral for the debt obligations had a carrying value of $167 million and $163 million at March 31, 2011 and December 31, 2010, respectively, and primarily consist of property, plant and equipment.

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has 16 power purchase agreements ("PPAs") that are considered variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to operate the plants and 10 contracts with QFs 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.

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. These are accounted for at fair value. Under these contracts, SCE recovers the costs incurred under its approved long-term power procurement plans. 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 9, so there is no significant potential exposure to loss as a result of SCE's involvement with these VIEs. The aggregate capacity dedicated to SCE for these VIE projects was 3,820 MW at March 31, 2011 and the amounts that SCE paid to these projects were $86 million and $125 million for the three months ended March 31, 2011 and 2010, respectively. These amounts are recovered in customer rates.

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Equity Interests

EMG accounts for domestic energy projects in which it has a 50% or less ownership interest, and cannot exercise unilateral control, under the equity method. At March 31, 2011 and December 31, 2010, EMG had five significant variable interests in natural gas projects that are not consolidated, consisting of the Big 4 projects (Kern River, Midway-Sunset, Sycamore and Watson) and the Sunrise project. A subsidiary of EMG operates three of the four Big 4 projects and EMG's partner provides the fuel management services. In addition, the executive director of these projects is provided by EMG's partner. Commercial and operating activities are jointly controlled by a management committee of each VIE. Accordingly, EMG continues to account for its variable interests under the equity method.

At March 31, 2011 and December 31, 2010, EMG accounts for its interests in two renewable wind generating facilities, the Elkhorn Ridge and San Juan Mesa projects, under the equity method. The commercial and operating activities of these entities are directed by a management committee composed of representatives of each partner. Thus, EMG is not the primary beneficiary of these projects. In addition, EMG accounts for its interests in a wind project under construction, Community Wind North, under the equity method.

The following table presents the carrying amount of EMG's investments in unconsolidated VIEs and the maximum exposure to loss for each investment:

	March 31, 2011

(in millions)	Investment		Maximum Exposure

Natural gas-fired projects	$	315	$	315
Renewable energy projects		227		227

EMG's maximum exposure to loss in its VIEs 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 recourse to EMG. Accordingly, a default under such project financings 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, 2011, entities which EMG has accounted for under the equity method had indebtedness of $115 million, of which $41 million is proportionate to EMG's ownership interest in these two projects.

Note 4. Fair Value Measurements

Recurring 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 of an asset or liability should consider assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk.

Edison International categorizes financial assets and liabilities into a fair value hierarchy based on valuation inputs used to derive fair value. 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).

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

		As of March 31, 2011

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

Assets at Fair Value
Money market funds ²		$	1,044	$	—	$	—		$	—		$	1,044

Derivative contracts:
	Electricity		—		68		260			(54	)		274
	Natural gas		—		66		8			—			74
	Fuel oil		7		—		—			(7	)		—
	Tolling		—		—		122			—			122

Subtotal of commodity contracts			7		134		390			(61	)		470

Long-term disability plan			9		—		—			—			9

Nuclear decommissioning trusts:
	Stocks ³		2,068		—		—			—			2,068
	Municipal bonds		—		772		—			—			772
	Corporate bonds ⁴		—		320		—			—			320
	U.S. government and agency securities		251		103		—			—			354
	Short-term investments, primarily cash equivalents ⁵		—		80		—			—			80

Subtotal of nuclear decommissioning trusts			2,319		1,275		—			—			3,594

Total assets ⁶			3,379		1,409		390			(61	)		5,117

Liabilities at Fair Value
Derivative contracts:
	Electricity		—		13		53			(14	)		52
	Natural gas		—		255		7			(4	)		258
	Tolling		—		—		374			—			374

Subtotal of commodity contracts			—		268		434			(18	)		684
Interest rate contracts			—		14		—			—			14

Total liabilities			—		282		434			(18	)		698

Net assets (liabilities)		$	3,379	$	1,127	$	(44	)	$	(43	)	$	4,419

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		As of December 31, 2010

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

Assets at Fair Value
Money market funds ²		$	1,100	$	—	$	—	$	—		$	1,100

Derivative contracts:
	Electricity		—		70		363		(61	)		372
	Natural gas		1		69		11		(1	)		80
	Fuel oil		8		—		—		(8	)		—
	Tolling		—		—		118		—			118

Subtotal of commodity contracts			9		139		492		(70	)		570

Long-term disability plan			9		—		—		—			9

Nuclear decommissioning trusts:
	Stocks ³		2,029		—		—		—			2,029
	Municipal bonds		—		790		—		—			790
	Corporate bonds ⁴		—		346		—		—			346
	U.S. government and agency securities		215		73		—		—			288
	Short-term investments, primarily cash equivalents ⁵		1		31		—		—			32

Subtotal of nuclear decommissioning trusts			2,245		1,240		—		—			3,485

Total assets ⁶			3,363		1,379		492		(70	)		5,164

Liabilities at Fair Value
Derivative contracts:
	Electricity		—		13		40		(21	)		32
	Natural gas		—		286		11		(4	)		293
	Tolling		—		—		344		—			344
	Coal		—		1		—		(1	)		—

Subtotal of commodity contracts			—		300		395		(26	)		669
Interest rate contracts			—		16		—		—			16

Total liabilities			—		316		395		(26	)		685

Net assets (liabilities)		$	3,363	$	1,063	$	97	$	(44	)	$	4,479

¹: Represents the netting of assets and liabilities under master netting agreements and cash collateral across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.
²: Money market funds are included in cash and cash equivalents and restricted cash on Edison International's consolidated balance sheets.
³: Approximately 68% and 67% of the equity investments were located in the United States at March 31, 2011 and December 31, 2010, respectively.
⁴: Corporate bonds are diversified, and included $25 million and $27 million at March 31, 2011 and December 31, 2010, respectively, for collateralized mortgage obligations and other asset backed securities.
⁵: Excludes net receivables of $25 million and net liabilities of $5 million at March 31, 2011 and December 31, 2010, respectively, of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases.
⁶: Excludes $31 million at both March 31, 2011 and December 31, 2010, respectively, of cash surrender value of life insurance investments for deferred compensation.

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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)		2011			2010

Fair value, net asset at beginning of period		$	97		$	62
Total realized/unrealized gains (losses):
	Included in earnings ¹		—			45
	Included in regulatory assets and liabilities ²		(134	)		(487	)
	Included in accumulated other comprehensive income		1			6
Purchases			5			6
Settlements			(11	)		(28	)
Transfers in or out of Level 3			(2	)		(1	)

Fair value, net liability at end of period		$	(44	)	$	(397	)

Change during the period in unrealized losses related to assets and liabilities held at the end of the period ³		$	(139	)	$	(422	)

¹: Reported in "Competitive power generation" revenue on Edison International's consolidated statements 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 $(6) million and $46 million for the three months ended March 31, 2011 and 2010, respectively. The remainder of the unrealized losses relate to SCE. See 2 above.

Edison International determines the fair value for transfers in and transfers out of each level at the end of each reporting period. There were no significant transfers between levels during 2011 and 2010.

Valuation Techniques Used to Determine Fair Value

Level 1

Includes assets and liabilities where fair value is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. Financial assets and liabilities classified as Level 1 include exchange-traded equity securities, exchange traded derivatives, U.S. treasury securities and money market funds.

Level 2

Pricing inputs 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. Financial assets and liabilities utilizing Level 2 inputs include fixed-income securities and over-the-counter derivatives.

Derivative contracts that are over-the-counter traded are valued using pricing models to determine the net present value of estimated future cash flows and are generally classified as Level 2. Inputs to the pricing models include forward published or posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar instruments and discount rates. A primary source that best represents traded activity for each market is used 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 believed to provide the most liquid market for the commodity. Broker quotes are incorporated when corroborated with other information which may include a combination of prices from exchanges, other brokers and comparison to executed trades.

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Level 3

Includes financial assets and liabilities where fair value is determined using techniques that require significant unobservable inputs. Over-the-counter options, bilateral contracts, capacity contracts, QF contracts, derivative contracts that trade infrequently (such as congestion revenue rights ("CRRs") in the California market and over-the-counter derivatives at illiquid locations), long-term power agreements, and derivative contracts with counterparties that have significant nonperformance risks are generally valued using pricing models that incorporate unobservable inputs and are classified as Level 3. Assumptions are made in order to value derivative contracts in which observable inputs are not available. 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.

For derivative contracts that trade infrequently (illiquid financial transmission rights and CRRs), changes in fair value are based on models forecasting the value of those contracts. The models' inputs are reviewed and the fair value is adjusted when it is concluded that a change in inputs would result in a new valuation that better reflects the fair value of those derivative contracts. For illiquid long-term power agreements, fair value is based upon the 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. The fair value of the majority of SCE's derivatives that are classified as Level 3 is determined using uncorroborated non-binding broker quotes 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.

Nonperformance Risk

The fair value of the derivative assets and liabilities are adjusted for nonperformance risk. To assess nonperformance risks, SCE considers the probability of and the estimated loss incurred if a party to the transaction were to default. SCE also considers collateral, netting agreements, guarantees and other forms of credit support when assessing nonperformance. EMG 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 nonperformance risk adjustment represented an insignificant amount at both March 31, 2011 and December 31, 2010.

Nuclear Decommissioning Trusts

SCE's 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.

Fair Value of Long-Term Debt Recorded at Carrying Value

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

	March 31, 2011				December 31, 2010

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

Long-term debt, including current portion	$	12,575	$	12,314	$	12,419	$	12,360

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

The carrying value of trade receivables, payables and short-term debt approximates fair value.

Note 5. Debt and Credit Agreements

Project Financings

In February 2011, EME completed, through its subsidiary, Viento Funding II, Inc., an amendment of its 2009 non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The amendment increased the financing amount to $255 million, which included a $227 million ten-year term loan (expiring in December 2020), a $23 million seven-year letter of credit facility and a $5 million seven-year working capital facility. At March 31, 2011, $227 million was outstanding under this loan. The amount of outstanding letters of credit was $13 million. Interest under the term loan accrues at London Interbank Offered Rate (LIBOR) plus 2.75% initially with the rate increasing 0.25% on every fourth anniversary.

Credit Agreements

At March 31, 2011, SCE's outstanding short-term debt was $200 million at a weighted-average interest rate of 0.35%. This short-term debt was supported by a $2.4 billion credit facility. At December 31, 2010, there was no outstanding short-term debt. At March 31, 2011, letters of credit issued under SCE's credit facilities aggregated $73 million and are scheduled to expire in twelve months or less.

As of March 31, 2011, a subsidiary of EMG had a $10 million letter of credit facility with $2 million outstanding letters of credit.

At March 31, 2011, Edison International (Parent)'s outstanding short-term debt was $81 million at a weighted-average interest rate of 0.61%. At December 31, 2010, the outstanding short-term debt was $19 million at a weighted-average interest rate of 0.63%.

Letters of Credit

At March 31, 2011, standby letters of credit under EME's credit facility aggregated $80 million and were scheduled to expire as follows: $53 million in 2011 and $27 million in 2012. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $41 million, $3 million of which was under the Midwest Generation, LLC (Midwest Generation) credit facility, and were scheduled to expire as follows: $7 million in 2011, $16 million in 2012, $10 million in 2017, and $8 million in 2018. Certain letters of credit are subject to automatic annual renewal provisions.

Note 6. 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 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 electricity purchased from the California wholesale market as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities, power purchase agreements and CDWR contracts allocated to SCE.

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SCE's natural gas price exposure arises from natural gas purchased for generation at the Mountainview power plant and peaker plants, QF contracts where pricing is based on a monthly natural gas index and power purchase agreements in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.

Notional Volumes of Derivative Instruments

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

		Economic Hedges

Commodity	Unit of Measure	March 31, 2011		December 31, 2010

Electricity options, swaps and forwards	GWh		32,795		32,138
Natural gas options, swaps and forwards	Bcf		208		250
Congestion revenue rights	GWh		167,668		181,291
Tolling arrangements	GWh		113,541		114,599

Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at March 31, 2011:

	Derivative Assets									Derivative Liabilities

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

Non-trading activities
Economic hedges	$	85		$	302		$	387		$	225		$	475		$	700		$	313
Netting and collateral		(8	)		(13	)		(21	)		(10	)		(14	)		(24	)		(3	)

Total	$	77		$	289		$	366		$	215		$	461		$	676		$	310

The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2010:

	Derivative Assets						Derivative Liabilities

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

Non-trading activities
Economic hedges	$	87	$	367	$	454	$	216		$	449	$	665		$	211
Netting and collateral		—		—		—		(4	)		—		(4	)		(4	)

Total	$	87	$	367	$	454	$	212		$	449	$	661		$	207

Income Statement Impact of Derivative Instruments

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

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The following table summarizes the components of economic hedging activity:

	Three months ended March 31,

(in millions)	2011			2010

Realized losses	$	(39	)	$	(24	)
Unrealized losses		(96	)		(581	)

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 $82 million and $67 million as of March 31, 2011 and December 31, 2010, respectively, for which SCE has posted no collateral and $4 million of collateral to its counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2011, SCE would be required to post $2 million of collateral.

Counterparty Default Risk Exposure

As part of SCE's procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. If a counterparty were to default on its contractual obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales of excess energy and realized gains on derivative instruments. However, all of the contracts that SCE has entered into with counterparties are either entered into under SCE's short-term or long-term procurement plan which has been approved by the CPUC, or the contracts are approved by the CPUC before becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance are not expected to affect earnings, but may temporarily affect cash flows.

To manage credit risk, SCE looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary.

Competitive Power Generation

EMG uses derivative instruments to reduce EMG's exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EMG's financial results can be affected by fluctuations in interest rates. The derivative financial instruments vary in duration, ranging from a few days to several years, depending upon the instrument. 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 Edison International's consolidated balance sheets with offsetting changes recorded on the consolidated statements of income. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized, to the extent effective, on Edison International's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive income until the related forecasted

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transaction occurs. The results of derivative activities are recorded in cash flows from operating activities on the consolidated statements of cash flows.

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

Where EMG's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EMG presents its derivative assets and liabilities on a net basis on the consolidated balance sheets.

Notional Volumes of Derivative Instruments

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

March 31, 2011

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

Electricity	Forwards/Futures	Sales	GWh		16,899	¹		20,400	³		33,336
Electricity	Forwards/Futures	Purchases	GWh		306	¹		21,079	³		35,455
Electricity	Capacity	Sales	MW-Day (in thousands)		186	²		—			123	²
Electricity	Capacity	Purchases	MW-Day (in thousands)		21	²		—			379	²
Electricity	Congestion	Sales	GWh		—			136	⁴		9,244	⁴
Electricity	Congestion	Purchases	GWh		—			863	⁴		146,786	⁴
Natural gas	Forwards/Futures	Sales	bcf		—			—			27.4
Natural gas	Forwards/Futures	Purchases	bcf		—			—			28.6
Fuel oil	Forwards/Futures	Sales	barrels		—			—			35,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			240,000			35,000
Coal	Forwards/Futures	Sales	tons		—			—			2,731,000
Coal	Forwards/Futures	Purchases	tons		—			—			2,638,000

(in millions)

Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date

Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt	Cash flow	$	92	June 2016
Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.415%) debt	Cash flow		113	December 2020
Amortizing interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt	Cash flow		122	December 2025
Amortizing forward starting interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt	Cash flow		68	March 2026

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December 31, 2010

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

Electricity	Forwards/Futures	Sales	GWh		16,799	¹		22,456	³		34,630
Electricity	Forwards/Futures	Purchases	GWh		408	¹		22,931	³		37,669
Electricity	Capacity	Sales	MW-Day (in thousands)		190	²		—			136	²
Electricity	Capacity	Purchases	MW-Day (in thousands)		8	²		—			419	²
Electricity	Congestion	Sales	GWh		—			136	⁴		12,020	⁴
Electricity	Congestion	Purchases	GWh		—			1,143	⁴		187,689	⁴
Natural gas	Forwards/Futures	Sales	bcf		—			—			30.6
Natural gas	Forwards/Futures	Purchases	bcf		—			—			34.3
Fuel oil	Forwards/Futures	Sales	barrels		—			250,000			10,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			490,000			10,000
Coal	Forwards/Futures	Sales	tons		—			—			2,630,500
Coal	Forwards/Futures	Purchases	tons		—			—			2,645,500

(in millions)

Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date

Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt	Cash flow	$	138	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
Amortizing forward starting interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt	Cash flow		68	March 2026

¹: EMG's hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power contracts for the coal plants which meet the normal purchases and sales 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 Reliability Pricing Model (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.

Fair Value of Derivative Instruments

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

March 31, 2011

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

Non-trading activities
Cash flow hedges	$	44		$	6		$	50		$	9		$	23		$	32		$	18
Economic hedges		59			6			65			56			1			57			8
Trading activities		139			96			235			106			26			132			103

		242			108			350			171			50			221			129
Netting and collateral received ¹		(204	)		(42	)		(246	)		(164	)		(35	)		(199	)		(47	)

Total	$	38		$	66		$	104		$	7		$	15		$	22		$	82

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December 31, 2010

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

Non-trading activities
Cash flow hedges	$	54		$	2		$	56		$	10		$	25		$	35		$	21
Economic hedges		77			2			79			71			—			71			8
Trading activities		184			103			287			148			29			177			110

		315			107			422			229			54			283			139
Netting and collateral received ¹		(269	)		(37	)		(306	)		(223	)		(35	)		(258	)		(48	)

Total	$	46		$	70		$	116		$	6		$	19		$	25		$	91

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

Income Statement Impact of Derivative Instruments

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

	Cash Flow Hedge Activity ¹ Three Months Ended March 31,

	Cash Flow Hedge Activity ¹ Three Months Ended March 31,						Income Statement Location
(in millions)	2011			2010			Income Statement Location

Accumulated other comprehensive income derivative gain at January 1	$	27		$	175
Effective portion of changes in fair value		10			157
Reclassification from accumulated other comprehensive income to net income		(16	)		(34	)	Competitive power generation

Accumulated other comprehensive income derivative gain at March 31	$	21		$	298

¹: Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at March 31, 2011 and 2010 were $12 million and $180 million, respectively.

For additional information related to accumulated other comprehensive income, see Note 11.

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 $2 million and $9 million during the first quarters of 2011 and 2010, respectively, in competitive power generation revenues on the consolidated statements of income representing the amount of cash flow hedge ineffectiveness.

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,

(in millions)	Income Statement Location	2011		2010

Economic hedges	Competitive power generation	$	6	$	(4	)
	Fuel		6		1
Trading activities	Competitive power generation		16		47

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Contingent Features

Certain derivative instruments contain margin and collateral deposit requirements. Since EMG's credit ratings are below investment grade, EMG has provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties. The aggregate fair value of all derivative instruments with credit-risk-related contingent features was in an asset position at March 31, 2011 and, accordingly, the contingent features described below do not currently have liquidity exposure. Certain derivative contracts do not require margin, but contain provisions that require EMG 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 EMG 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. Future increases in power prices could expose EMG, Midwest Generation or EMMT to termination payments or additional collateral postings under the contingent features described above.

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 fair value of the related positions. Edison International nets counterparty receivables and payables where balances exist under master netting agreements. Edison International presents the portion of its margin and collateral deposits 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, 2011		December 31, 2010


Collateral provided to counterparties:
	Offset against derivative liabilities	$	5	$	8
	Reflected in margin and collateral deposits		50		65
Collateral received from counterparties:
	Offset against derivative assets		48		52

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Note 7. Income Taxes

Effective Tax Rate

The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations.

		Three months ended March 31,

(in millions)		2011			2010

Income from continuing operations before income taxes		$	281		$	393

Provision for income tax at federal statutory rate of 35%			98			138
Increase (decrease) in income tax from:
	State tax – net of federal benefit		9			14
	Health care legislation ¹		—			39
	Production and housing credits		(18	)		(15	)
	Property-related and other		(24	)		(26	)

Total income tax expense from continuing operations		$	65		$	150

Effective tax rate			23	%		38	%

¹: During the first quarter of 2010, Edison International recorded a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.

The CPUC requires flow-through ratemaking 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.

Accounting for Uncertainty in Income Taxes

Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. The guidance requires the disclosure of all unrecognized tax benefits, which includes both the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims.

Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits:

(in millions)		2011			2010


Balance at January 1,		$	565		$	664
Tax positions taken during the current year:
	Increases		20			16
Tax positions taken during a prior year:
	Increases		—			123
	Decreases		(5	)		(20	)

Balance at March 31,		$	580		$	783

As of March 31, 2011 and December 31, 2010, respectively, if recognized, $460 million and $455 million of the unrecognized tax benefits would impact the effective tax rate.

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Edison International's federal income tax returns and its California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 are currently under review by the Franchise Tax Board. The IRS examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included proposed adjustments for the following two items:

•: A proposed adjustment increasing the taxable gain on the 2004 sale of EMG's international assets, which if sustained, would result in a federal tax payment of approximately $187 million, including interest and penalties (the IRS has asserted a 40% penalty for understatement of tax liability related to this matter).
•: A proposed adjustment to disallow a component of SCE's repair allowance deduction, which if sustained, would result in a federal tax payment of approximately $90 million, including interest.

Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011.

Accrued Interest and Penalties

The total amount of accrued interest and penalties related to Edison International's income tax liabilities was $217 million and $213 million as of March 31, 2011 and December 31, 2010, respectively.

The net after-tax interest and penalties recognized in income tax expense was $3 million and $15 million for the three months ended March 31, 2011 and 2010, respectively.

Note 8. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

During the three months ended March 31, 2011, Edison International made 2010 plan year contributions of $2 million, 2011 plan year contributions of $28 million and expects to make $4 million of additional 2010 plan year contributions and $96 million of additional 2011 plan year contributions during the remainder of 2011. Annual contributions made to most of SCE's pension plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.

Expense components are:

	Three months ended March 31,

(in millions)	2011			2010

Service cost	$	43		$	34
Interest cost		52			54
Expected return on plan assets		(60	)		(52	)
Amortization of prior service cost		2			2
Amortization of net loss		6			7

Expense under accounting standards		43			45
Regulatory adjustment – deferred		(6	)		(14	)

Total expense recognized	$	37		$	31

Postretirement Benefits Other Than Pensions

During the three months ended March 31, 2011, Edison International made 2011 plan year contributions of $6 million and expects to make $50 million of additional contributions during the remainder of 2011. Annual contributions made to SCE plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.

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Expense components are:

	Three months ended March 31,

(in millions)	2011			2010

Service cost	$	11		$	8
Interest cost		33			31
Expected return on plan assets		(28	)		(25	)
Amortization of prior service cost (credit)		(9	)		(9	)
Amortization of net loss		9			8

Total expense	$	16		$	13

Stock-Based Compensation

During the first quarter of 2011, Edison International granted its 2011 stock-based compensation awards, which included stock options, performance shares and restricted stock units.

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 (in millions)

Outstanding at December 31, 2010		19,142,209		$	33.28
Granted		3,228,721			37.92
Expired		(51,629	)		48.45
Forfeited		(117,177	)		31.18
Exercised		(508,164	)		25.09

Outstanding at March 31, 2011		21,693,960			34.14		6.51

Vested and expected to vest at March 31, 2011		21,205,360			34.15		6.46	$	115

Exercisable at March 31, 2011		13,075,275			34.35		5.02		83

At March 31, 2011, there was $32 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately three years.

Performance Shares

The following is a summary of the status of Edison International nonvested performance shares:

	Equity Awards

	Equity Awards					Liability Awards
				Weighted-Average Grant Date Fair Value		Liability Awards
	Shares			Weighted-Average Grant Date Fair Value		Shares			Weighted-Average Fair Value

Nonvested at December 31, 2010		415,028		$	30.99		415,028		$	34.74
Granted		144,624			31.65		144,624
Forfeited		(108,648	)		44.09		(108,648	)

Nonvested at March 31, 2011		451,004			28.05		451,004			26.02

The current portion of nonvested performance shares classified as liability awards is reflected in "Other current liabilities" and the long-term portion is reflected in "Pensions and benefits" on the consolidated balance sheets.

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At March 31, 2011, there was $7 million (based on the March 31, 2011 fair value of performance shares classified as equity awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately two years.

Restricted Stock Units

The following is a summary of the status of Edison International nonvested restricted stock units granted to SCE employees:

			Weighted-Average Grant Date Fair Value


Nonvested at December 31, 2010	644,796		$	32.18
Granted	241,417			37.93
Forfeited	(7,448	)		30.95
Paid Out	(93,831	)		54.85

Nonvested at March 31, 2011	784,934		$	31.89

At March 31, 2011, there was $14 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $6 million in 2011, $6 million in 2012 and $2 million in 2013.

Supplemental Data on Stock Based Compensation

		Three months ended March 31,

(in millions, except per award amounts)		2011		2010

Stock based compensation expense ¹		$	6	$	8
Income tax benefits related to stock compensation expense			2		3
Excess tax benefits ²			2		1
Stock options
	Cash used to purchase shares to settle options		19		7
	Cash from participants to exercise stock options		13		5
	Value of options exercised		6		2
Restricted stock units
	Value of shares settled		5		—
	Tax benefits realized from settlement of awards		2		—

¹: Reflected in "Operations and maintenance" on the consolidated statements of income.
²: Reflected in "Settlements of stock based compensation—net" in the financing section of the consolidated statements of cash flows.

No performance shares were settled as of March 31, 2011 and 2010, respectively.

Note 9. Commitments and Contingencies

Third-Party Power Purchase Agreements

During the first quarter of 2011, SCE entered into a renewable energy power purchase contract which is classified as an operating lease. SCE's additional commitments under this contract are estimated to be: $29 million each year in 2012 – 2015 and $468 million for the period remaining thereafter.

Other Commitments

Fuel Supply Contracts

At March 31, 2011, Midwest Generation and EMG Homer City Generation L.P. ("Homer City") had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses.

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These commitments are estimated to aggregate $677 million, summarized as follows: $373 million for the remainder of 2011, $255 million in 2012 and $49 million in 2013.

Turbine Commitments

At March 31, 2011, EMG had commitments to purchase wind turbines of $90 million due in 2011. EMG's failure to schedule turbine delivery by June 2011 would result in a termination obligation equal to its turbine deposit, which would result in a $21 million charge against earnings. EMG has identified a project in which to place these turbines. However, there is no assurance that development will be completed and the turbines will be used for this project.

On October 8, 2010, an agreement was reached to settle disputes included in the complaint filed by EMG against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. As a result of this agreement, EMG may elect to deploy up to 60 additional wind turbines (aggregating 144 MW) that were part of the original contract, or may be obligated to make a payment of up to $30 million following the end of the three-year period if it has not elected to deploy the additional turbines and if certain other criteria apply. In April 2011, the 55 MW Pinnacle wind project in West Virginia, which will deploy the 23 wind turbines purchased from Mitsubishi, commenced construction.

Capital Expenditures

At March 31, 2011, EMG's subsidiaries had firm commitments to spend approximately $153 million during the remainder of 2011 on capital and construction expenditures. These expenditures primarily relate to selective non-catalytic reduction ("SNCR") equipment at the Midwest Generation plants, the construction of wind projects and non-environmental improvements at the coal plants. 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.

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

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future

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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 2012. There were approximately 228 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at March 31, 2011. Midwest Generation had recorded a liability of $56 million at March 31, 2011 related to this contract indemnity.

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 Plant

In connection with the acquisition of the Homer City plant, Homer City agreed to indemnify the sellers with respect to specified environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed this obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City plant, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnity provisions, they are not subject to a maximum potential liability and do not have expiration dates. For discussion of the New Source Review lawsuit filed against Homer City, see "—Contingencies—Homer City New Source Review Lawsuit." 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, 2011, EME had recorded a liability of $44 million related to these matters.

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

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Indemnity Provided as Part of the Acquisition of Mountainview

In connection with the acquisition of the Mountainview power plant, 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

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

Other Edison International Indemnities

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 the outcome of these other proceedings will not materially affect its results of operations or liquidity.

Midwest Generation New Source Review Lawsuit

In August 2009, the United States Environmental Protection Agency ("US EPA") and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging that Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration ("PSD") requirements and of the New Source Performance Standards of the Clean Air Act ("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. 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 the requirements of the Combined Pollutant Standard ("CPS"). Several Chicago-based environmental action groups have intervened in the case.

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In March 2010, nine of the ten counts related to PSD requirements in the complaint were dismissed, and the tenth count was also dismissed to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. Following those dismissals, the government plaintiffs filed an amended complaint, with claims that attempted to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. In March 2011, the court again dismissed the nine PSD claims previously dismissed in 2010, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court also dismissed all claims asserted against Commonwealth Edison and EME. The court denied a motion to dismiss a claim by the Chicago-based environmental action groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the court that the statute of limitations should be equitably tolled. The court did not address 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. Trial of the liability portion of the case is scheduled to commence June 3, 2013.

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

Homer City New Source Review Lawsuit

In January 2011, the US EPA filed a complaint in the Western District of Pennsylvania against Homer City, the sale-leaseback owner participants of the Homer City plant, and two prior owners of the Homer City plant. The complaint alleges violations of the PSD and Title V provisions of the CAA and its implementing regulations, including requirements contained in the Pennsylvania State Implementation Plan, as a result of projects in the 1990s performed by prior owners without PSD permits and the subsequent failure to incorporate emissions limitations that meet BACT into the station's Title V operating permit. In addition to seeking penalties ranging from $32,500 to $37,500 per violation, per day, the complaint calls for an injunction ordering Homer City 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. Pennsylvania Department of Environmental Protection, the State of New York and the State of New Jersey have intervened in the lawsuit.

Also in January 2011, two residents filed a complaint in the Western District of Pennsylvania, on behalf of themselves and all others similarly situated, against Homer City, the sale-leaseback owner participants of the Homer City plant, two prior owners of the Homer City plant, EME, and Edison International, claiming that emissions from the Homer City plant had adversely affected their health and property values. The plaintiffs seek to have their suit certified as a class action and request injunctive relief, the funding of a health assessment study and medical monitoring, compensatory and punitive damages.

In April 2011, Homer City filed motions to dismiss both complaints. An adverse decision could involve penalties, remedial actions and damages that could have a material adverse impact on the financial condition and results of operations of Homer City and EME. EME cannot predict the outcome of these matters or estimate the impact on the Homer City plant, or its and Homer City's 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. No trial date has been set for this litigation. 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. In October 2010, the Hopi Tribe settled all of its claims and the remaining parties

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agreed to engage in mediation. SCE cannot predict the outcome of the Navajo Nation's complaint against SCE.

Environmental Remediation

Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.

As of March 31, 2011, Edison International's recorded estimated minimum liability to remediate its 29 identified material sites (sites in which the upper end of the range of costs is at least $1 million) at SCE (24 sites) and EMG (5 sites primarily related to Midwest Generation) was $59 million, of which $52 million was related to SCE, including $20 million related to San Onofre. In addition to its identified material sites, SCE also has 33 immaterial sites for which the total minimum recorded liability was $3 million. 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 material sites and immaterial sites could exceed its recorded liability by up to $190 million and $7 million, respectively, 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.

The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $28 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE recovers 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 $52 million at March 31, 2011 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 $4 million and less than $1 million for the three months ended March 31, 2011 and 2010, respectively.

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

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Nuclear Insurance

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

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

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $48 million per year. Insurance premiums are charged to operating expense.

Spent Nuclear Fuel

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

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

Note 10. Regulatory and Environmental Developments

Environmental Developments

Greenhouse Gas Regulation

In March 2011, a California court issued an order suspending CARB's regulations implementing a California cap-and-trade program. The order would also potentially apply to other measures included in the regulations. The CARB has the right to appeal the ruling.

In April 2011, California enacted a law requiring that California utilities purchase 33% of their electricity requirements from renewable resources. The law requires the CPUC to adopt implementing regulations. The impact of the new 33% law will depend on the content of yet to be adopted implementing regulations, which remains uncertain.

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Hazardous Air Pollutant Regulations

In March 2011, the US EPA issued draft "National Emission Standards for Hazardous Air Pollutants," limiting emissions of hazardous air pollutants ("HAPs") from coal- and oil-fired electrical generating units. The regulations are expected to be finalized by November 2011. Based on its continuing review, EMG does not expect these standards, if adopted, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. Midwest Generation expects to continue to develop and implement a compliance program that includes the use of activated carbon injection, upgrades to particulate removal systems and dry sorbent injection, combined with its use of low sulfur Powder River Basin ("PRB") coal, to meet emission limits for criteria pollutants, such as nitrogen oxide ("NO _x ") and sulfur dioxide ("SO ₂ ") as well as for HAPs, such as mercury, acid gas and non-mercury metals. With respect to the Homer City plant, the proposed standards, like the pending Clean Air Transport Rule, will require additional reductions in and controls for SO ₂ emissions.

Water Quality

Once-Through Cooling Issues

In March 2011, the US EPA proposed draft standards under the federal Clean Water Act which would affect cooling water intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). The regulations are expected to be finalized by July 2012. Edison International is still evaluating the proposed standards but believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable without incurring material additional capital expenditures or operating costs for both the Midwest Generation plants and the Homer City plant. The required measures to comply with the proposed standards regarding entrainment are subject to the discretion of the permitting authority, and Edison International is unable at this time to assess potential costs of compliance, which could be significant for the Midwest Generation plants and San Onofre, but are not expected to be material for the Homer City plant, which already has cooling towers.

In addition to the proposed draft US EPA standards, the existing California once-through cooling policy may result in significant capital expenditures at San Onofre and may affect its operations. The California policy may also significantly impact SCE's ability to procure generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems, system reliability and the cost of electricity if other coastal power plants in California are forced to shut down or limit operations.

Note 11. Accumulated Other Comprehensive Loss

Edison International's accumulated other comprehensive loss consists of:

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


Balance at December 31, 2010	$	16		$	(87	)	$	(5	)	$	(76	)
Current period change		(4	)		3			—			(1	)

Balance at March 31, 2011	$	12		$	(84	)	$	(5	)	$	(77	)

Included in accumulated other comprehensive loss at March 31, 2011 was $21 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $9 million, net of tax, of unrealized losses related to interest rate hedges. The maximum period over which a commodity cash flow hedge is designated is May 31, 2014.

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 $21 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that

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reclassification of net unrealized gains will increase energy revenues 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.

Note 12. Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

			Three months ended March 31,

(in millions)			2011			2010

Cash payments (receipts) for interest and taxes:
	Interest – net of amounts capitalized		$	155		$	137
	Tax payments (refunds) – net			(45	)		10

Noncash investing and financing activities:
	Accrued capital expenditures		$	461		$	309
	Consolidation of variable interest entities:
		Assets other than cash	$	—		$	(94	)
		Liabilities and noncontrolling interests		—			99
	Deconsolidation of variable interest entities:
		Assets other than cash	$	—		$	380
		Liabilities and noncontrolling interests		—			(476	)
	Dividends declared but not paid:
		Common stock	$	104		$	103
		Preferred and preference stock of utility		10			8

Note 13. Preferred and Preference Stock of Utility

In March 2011, SCE issued 1,250,000 shares of 6.5% Series D preference stock (cumulative, $100 liquidation value). The Series D preference stock may not be redeemed prior to March 1, 2016. After March 1, 2016, SCE may, at its option, redeem the shares, in whole or in part. These shares are not subject to mandatory redemption.

Note 14. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)		March 31, 2011		December 31, 2010


Current:
	Regulatory balancing accounts	$	227	$	213
	Energy derivatives		173		162
	Other		7		3

			407		378

Long-term:
	Deferred income taxes – net		1,878		1,855
	Pensions and other postretirement benefits		1,094		1,097
	Unamortized generation investment – net		339		355
	Unamortized loss on reacquired debt		263		268
	Energy derivatives		261		177
	Nuclear-related ARO investment – net		167		154
	Unamortized distribution investment – net		109		105
	Regulatory balancing accounts		52		56
	Other		287		280

			4,450		4,347

Total Regulatory Assets		$	4,857	$	4,725

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Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	March 31, 2011		December 31, 2010


Current:
Regulatory balancing accounts	$	775	$	733
Other		3		5

		778		738

Long-term:
Costs of removal		2,648		2,623
ARO		1,251		1,099
Regulatory balancing accounts		834		802

		4,733		4,524

Total Regulatory Liabilities	$	5,511	$	5,262

Note 15. Other Investments

Nuclear Decommissioning Trusts

Future nuclear decommissioning costs of removal of nuclear assets are expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately $23 million per year included in SCE customer rates. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through customer rates. 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.

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

		Amortized Cost				Fair Value


(in millions)	Longest Maturity Dates	March 31, 2011		December 31, 2010		March 31, 2011		December 31, 2010

Stocks	—	$	845	$	895	$	2,068	$	2,029
Municipal bonds	2049		683		706		772		790
Corporate bonds	2044		263		288		320		346
U.S. government and agency securities	2040		331		270		354		288
Short-term investments and receivables/payables	One-year		100		26		105		27

Total		$	2,222	$	2,185	$	3,619	$	3,480

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Proceeds from sales of securities (which are reinvested) were $622 million and $286 million for the three months ended March 31, 2011 and 2010, respectively. Unrealized holding gains, net of losses, were $1.4 billion and $1.3 billion at March 31, 2011 and December 31, 2010, 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:

(in millions)	2011			2010


Balance at January 1,	$	3,480		$	3,140
Realized gains – net		23			21
Unrealized gains – net		102			62
Other-than-temporary impairments		(9	)		(3	)
Interest, dividends, contributions and other		23			28

Balance at March 31,	$	3,619		$	3,248

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

Note 16. Other Income and Expenses

Other income and expenses are as follows:

		Three months ended March 31,

(in millions)		2011		2010

Other income:
	Equity AFUDC	$	29	$	27
	Increase in cash surrender value of life insurance policies		7		6
	Other		2		1

Total utility other income			38		34
Competitive power generation and other income			3		—

Total other income		$	41	$	34

Other expenses:
	Civic, political and related activities and donations	$	7	$	5
	Other		6		5

Total utility other expenses			13		10
Competitive power generation and other expenses			—		(2	)

Total other expenses		$	13	$	8

Note 17. Business Segments

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Reportable Segments Information

The following is information (including the elimination of intercompany transactions) related to Edison International's reportable segments:

	Three months ended March 31,

(in millions)	2011			2010

Operating Revenue:
Electric utility	$	2,232		$	2,159
Competitive power generation		552			652
Parent and other ²		(2	)		(1	)

Consolidated Edison International		2,782			2,810

Net Income (Loss) attributable to Edison International:
Electric utility		222			164
Competitive power generation ¹		(20	)		77
Parent and other ²		(2	)		(5	)

Consolidated Edison International	$	200		$	236

Segment balance sheet information was:

(in millions)		March 31, 2011		December 31, 2010


Total Assets:
	Electric utility	$	36,344	$	35,906
	Competitive power generation		9,771		9,597
	Parent and other ²		46		27

Consolidated Edison International		$	46,161	$	45,530

¹: Includes earnings (losses) from discontinued operations of $(2) million and $6 million for the three months ended March 31, 2011 and 2010, 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 quarterly report on Form 10-Q 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:

•: cost of capital and the ability of Edison International or its subsidiaries to borrow funds and access the capital markets on reasonable terms;
•: 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;
•: 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;
•: risks associated with the operation of transmission and distribution assets and nuclear and other power generating facilities including: nuclear fuel storage issues, failure, availability, efficiency, output, cost of repairs and retrofits of equipment and availability and cost of spare parts;
•: 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;
•: 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;
•: 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;
•: 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;

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•: 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;
•: 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;
•: risks that competing transmission systems will be built by merchant transmission providers in SCE's territory; and
•: weather conditions and natural disasters.

Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in Edison International's 2010 Form 10-K, including the "Risk Factors" section in Part I, Item 1A. Readers are urged to read this entire report, including the information incorporated by reference, as well as the 2010 Form 10-K, 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 U.S. Securities and Exchange Commission.

This MD&A for the three months ended March 31, 2011 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2010, and as compared to the three months ended March 31, 2010. This discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2010 (the "year-ended 2010 MD&A"), which was included in the 2010 Form 10-K.

EDISON INTERNATIONAL MANAGEMENT OVERVIEW

Highlights of Operating Results

		Three months ended March 31,


(in millions)		2011			2010			Change

Net Income (Loss) Attributable to Edison International
	SCE	$	222		$	164		$	58
	EMG		(20	)		77			(97	)
	Edison International Parent and Other		(2	)		(5	)		3

	Edison International Consolidated		200			236			(36	)

Non-Core Items
	SCE – tax impact of health care legislation		—			(39	)		39
	EMG discontinued operations		(2	)		6			(8	)

	Total non-core items		(2	)		(33	)		31

Core Earnings (Losses)
	SCE		222			203			19
	EMG		(18	)		71			(89	)
	Edison International Parent and Other		(2	)		(5	)		3

	Edison International Consolidated	$	202		$	269		$	(67	)

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Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings by principal operating subsidiary internally for financial planning and for analysis of performance. Core earnings (losses) 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 less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including lease terminations, sale of certain assets, early debt extinguishment costs and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings.

SCE's 2011 core earnings increased $19 million primarily due to rate base growth.

EMG's 2011 core earnings decreased $89 million primarily due to unplanned outages at Homer City, lower energy prices, distributions from EMG's Doga and March Point projects during 2010 (none received in 2011) and lower trading revenue.

Consolidated non-core items for Edison International included an after tax earnings charge of $39 million recorded in 2010 to reverse previously recognized federal tax benefits eliminated by federal health care legislation enacted in 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.

Management Overview of SCE

Capital Program

During the first quarter, SCE's capital investment program focused on upgrading, maintaining and expanding SCE's transmission and distribution system; maintaining and replacing generation asset equipment; and installing smart meters. Total capital expenditures (including accruals) were $765 million during the first quarter of 2011 compared to $640 million during the same period in 2010.

SCE continues to project that 2011 capital investments will be in the range of $3.9 billion to $4.4 billion and that 2011 – 2014 total capital investment spending will be in the range of $15.6 billion to $17.5 billion. Actual capital spending will be affected by regulatory approval, permitting, market and other factors as discussed further under "SCE: Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2010 MD&A.

2012 CPUC General Rate Case

As discussed in the year-ended 2010 MD&A, SCE is required to update its 2012 GRC application to reflect, among other things, the impacts of governmental and legislative actions. In April 2011, the IRS issued guidance for determining bonus depreciation enacted in the 2010 Tax Relief Act. On April 28, 2011, SCE submitted an update of its 2012 GRC application primarily to reflect bonus depreciation deductions under the 2010 Tax Relief Act, reducing its base rate revenue requirement by $38 million, $133 million and $145 million in 2012, 2013 and 2014, respectively. The decrease in base rate revenue requirement is due to a reduction in rate base from inclusion of higher deferred income taxes resulting from bonus depreciation. SCE's revised request, after considering the effects of sales growth, would result in incremental customer rate increases of $828 million, $152 million and $514 million in 2012, 2013 and 2014, respectively.

The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011. To the extent a final decision is delayed, the CPUC has authorized the establishment of a GRC memorandum account, which will make the revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.

Nuclear Industry and Regulatory Response to Events in Japan

As discussed in the 2010 Form 10-K under the heading "Nuclear Power Plant Regulation," SCE is subject to the jurisdiction of the NRC with respect to its ownership interest in San Onofre and Palo Verde. In light of the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the recent earthquake and tsunami, the NRC plans to perform additional operational and safety reviews of nuclear

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facilities in the United States. The lessons learned from the Japanese events and NRC reviews may impact future operations and capital requirements at United States nuclear facilities, including the operations and capital requirements of SCE's nuclear facilities.

Management Overview of EMG

The profitability of EMG's competitive power generation operations is expected to be significantly lower in 2011 as a result of lower realized energy prices driven by the expiration of hedge contracts, higher fuel costs and unplanned outages at the Homer City plant during the first quarter. In addition, the profitability of EME's Midwest Generation plants is expected to be adversely affected in 2012 by a decline in capacity prices (projected to begin in June 2012) and higher rail transportation costs (due to the expiration at the end of 2011 of a favorable long-term rail contract). As a result, EMG may incur net losses during 2011 and in subsequent years unless energy prices recover or its costs decline.

At March 31, 2011, EMG and its subsidiaries had $1.2 billion in cash and cash equivalents and $981 million of liquidity available from credit facilities that expire in 2012. EMG's principal subsidiary, EME, had $3.7 billion of senior notes outstanding at March 31, 2011, $500 million of which mature in 2013. EMG's business plans are focused on operating effectively through the current commodity price cycle and on environmental compliance and renewable energy plans as described below.

Midwest Generation Environmental Compliance Plans and Costs

During the first quarter of 2011, Midwest Generation continued its permitting and planning activities for NO _x and SO ₂ controls to meet the requirements of the CPS. In February 2011, the Illinois Environmental Protection Agency issued construction permits authorizing Midwest Generation to install a dry sorbent injection system using Trona or other sodium-based sorbents at the Powerton Station's Units 5 and 6.

Decisions regarding whether or not to proceed with retrofitting units to comply with CPS requirements for SO ₂ emissions remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation could also elect to temporarily or permanently shut down units, instead of installing controls, to be in compliance with the CPS.

Therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation intends to defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others.

In March 2011, the US EPA issued draft "National Emission Standards for Hazardous Air Pollutants," limiting emissions of HAPs from coal- and oil-fired electrical generating units. The regulations are expected to be finalized by November 2011. Based on its continuing review, EME does not expect these standards, if adopted, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. Midwest Generation expects to continue to develop and implement a compliance program that includes the use of activated carbon injection, upgrades to particulate removal systems and dry sorbent injection, combined with its use of low sulfur PRB coal, to meet emissions limits for criteria pollutants, such as NO _x and SO ₂ as well as for HAPs, such as mercury, acid gas and non-mercury metals.

Homer City Outage

On February 10, 2011, a steam pipe ruptured at Unit 1 of the Homer City plant, taking the unit off line. Homer City took Unit 2 off line, which has the same design and operating conditions, to further evaluate the equipment due to the risk of a similar failure. On April 5, 2011, Unit 1 returned to service after making needed repairs, including replacing all pipes similar to the ruptured pipe. Unit 2 is undergoing similar repairs and is expected to return to service in the second quarter of 2011.

The unplanned outages at Units 1 and 2 and the continuation of low power prices have impacted Homer City's liquidity. As a result, in order to have sufficient working capital available for operating expenses and

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to pay the equity portion of Homer City's rent payment that was due April 1, 2011 to the owner-lessors, Homer City had to defer certain fuel deliveries, arrange for accelerated payments by EMMT for future energy deliveries under an intercompany agreement in place between EMMT and Homer City, and draw $12 million from the $20 million equity rent reserve established under its sale-leaseback transaction documents. Homer City must restore the equity rent reserve account and continue to make equity rent payments in order to be entitled to make future distributions. The advance payments made and currently anticipated in April are expected to total approximately $30 million. It is currently anticipated that all such amounts will be applied against amounts invoiced by EMMT under an intercompany agreement within the next six months, but the actual rate at which such advance payments will be applied will depend upon prevailing power prices and other factors. To further stabilize Homer City's liquidity, effective April 1, 2011, EMMT assigned to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. Accordingly, effective April 1, 2011, these revenues will now be recorded as part of Homer City's revenues in lieu of their prior classification as EMMT trading revenues. EMMT realized trading revenues of $28 million under this arrangement in 2010.

The actions described above also resulted in Homer City being in compliance with the covenant requirements under the sale-leaseback documents at March 31, 2011. Under these documents, the rent payments are comprised of two components, a senior rent portion and an equity rent portion. The senior rent is used exclusively for debt service to the holders of the senior secured bonds issued in connection with the sale-leaseback transaction, while the equity rent is paid to the owner-lessors. In order to pay the equity portion of the rent, among other requirements, Homer City is required to meet historical and projected senior rent service coverage ratios of 1.7 to 1 (subject to reduction to 1.3 to 1 under certain circumstances).

For additional information, see "EMG: Liquidity and Capital Resources—Debt Covenants and Dividend Restrictions" and "Item 1A. Risk Factors—Risks Relating to EMG—Liquidity Risks" in the 2010 Form 10-K.

Environmental Regulation Developments

For a discussion of environmental regulation developments regarding Greenhouse Gas Regulation, Hazardous Air Pollutant Regulations and Once-Through Cooling Issues, see "Edison International Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments."

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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 – representing CPUC and FERC-authorized base rates, including the opportunity to earn the authorized return; and
•: Utility cost-recovery activities – representing CPUC-authorized balancing accounts which allow for recovery of costs incurred or provide for mechanisms to track and recover or refund differences in forecasted and actual amounts.

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 on capital projects recovered through CPUC-authorized mechanisms outside the GRC process. Differences between authorized amounts 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 that provide for recovery (with no return), 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.

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, 2011								Three months ended March 31, 2010


(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated

Operating revenue		$	1,363		$	869	$	2,232		$	1,265		$	894		$	2,159
Fuel and purchased power			—			584		584			—			689			689
Operations and maintenance			528			256		784			519			194			713
Depreciation, decommissioning and amortization			317			27		344			300			9			309
Property taxes and other			75			2		77			68			—			68

Total operating expenses			920			869		1,789			887			892			1,779

Operating income			443			—		443			378			2			380
Net interest expense and other			(84	)		—		(84	)		(72	)		(2	)		(74	)

Income before income taxes			359			—		359			306			—			306
Income tax expense			123			—		123			129			—			129

Net income			236			—		236			177			—			177
Dividends on preferred and preference stock			14			—		14			13			—			13

Net income available for common stock		$	222		$	—	$	222		$	164		$	—		$	164

Core Earnings ¹							$	222								$	203
Non-Core Earnings:
	Tax impact of health care legislation							—									(39	)

Total SCE GAAP Earnings							$	222								$	164

¹: See use of Non-GAAP financial measures in "Edison International Management Overview—Highlights of Operating Results."

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Utility Earning Activities

2011 vs. 2010

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $98 million primarily due to the following:

•: $45 million increase primarily due to a 4.35% increase in 2011 authorized revenue compared to the 2010 revenue requirement approved in the CPUC 2009 GRC decision.
•: $40 million increase in FERC-related revenue due to the implementation of the 2010 FERC rate case effective March 1, 2010 and construction work in progress ("CWIP") incentive earnings for the Tehachapi transmission project.
•: $15 million increase related to capital-related revenue requirements recovered through CPUC-authorized mechanisms outside of the GRC process primarily related to the steam generator replacement project and the EdisonSmartConnect™ project.

•

Higher depreciation, decommissioning and amortization expense of $17 million primarily related to increased capital expenditures, including capitalized software costs.

See "—Income Taxes" below for more information on lower income taxes during 2011 compared to the same period in 2010.

Utility Cost-Recovery Activities

2011 vs. 2010

Utility cost-recovery activities were primarily affected by the following:

•: Lower purchased power expense of $100 million related to: lower net ISO-related costs of $55 million primarily due to higher replacement power costs in 2010 related to the San Onofre Unit 2 extended outage and lower market prices in 2011; lower QF and renewable purchased power expense of $30 million primarily related to lower purchases due to expiration of a contract and lower natural gas prices; and lower bilateral energy purchase expense of $25 million primarily due to lower capacity payments as a result of expiring tolling contracts.
•: Higher operation and maintenance expense of $62 million for energy efficiency programs.
•: Higher depreciation, decommissioning and amortization expense of $18 million primarily related to the steam generator replacement project and the EdisonSmartConnect™ project.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $2.1 billion and $2.0 billion for the three months ended March 31, 2011 and 2010, respectively. The increase reflects a rate increase of $90 million and a sales volume increase of $30 million. The rate increase reflects higher system average rates for 2011 compared to the same period in 2010, primarily due to the implementation of rates authorized in the CPUC 2009 GRC decision and the 2010 FERC rate case. As a result of the CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk related to retail electricity sales (see "Item 1. Business—Southern California Edison Company—Overview of Ratemaking Mechanisms" in the 2010 Form 10-K).

SCE remits to CDWR and does not recognize as revenue the amounts that 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. The amounts collected and remitted to CDWR were $275 million and $296 million for the three months ended March 31, 2011 and 2010, respectively. The CDWR-related rates in 2011 continue to reflect an approximately $585 million refund of operating reserves that CDWR can release as their contracts terminate. Total customer rates are expected to increase as

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CDWR operating reserves are fully refunded. The power contracts that CDWR allocated to SCE will terminate by the end of 2011. SCE's revenue and related purchased power expense is expected to increase as these CDWR contracts are replaced by power purchase agreements entered into by SCE.

Income Taxes

The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision.

		Three months ended March 31,

(in millions)		2011			2010

Income before income taxes		$	359		$	306

Provision for income tax at federal statutory rate of 35%			125			107
Increase (decrease) in income tax from:
	State tax – net of federal benefit		12			9
	Health care legislation ¹		—			39
	Property-related and other		(14	)		(26	)

Total income tax expense		$	123		$	129

Effective tax rate			34	%		42	%

¹: See "Edison International Management Overview—Highlights of Operating Results" for a discussion of the $39 million non-cash charge related to the federal health care legislation enacted in March 2010.

The decreased benefit provided by property-related and other items was primarily due to lower deductions for asset removal costs and internally developed software in the first quarter of 2011 compared to the respective period in 2010.

LIQUIDITY AND CAPITAL RESOURCES

SCE's ability to operate its business, complete planned capital projects, and implement its business strategy are dependent upon its cash flow and access to the capital markets to finance its activities. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, dividend payments made to Edison International, and the outcome of tax and regulatory matters.

SCE expects to fund its continuing obligations, projected capital expenditures for 2011 and dividends to Edison International through cash and equivalents on hand, operating cash flows, tax benefits and capital market financings of debt and preferred equity, as needed. 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, 2011, SCE had approximately $53 million of cash and equivalents. SCE had two credit facilities: a $2.4 billion five-year credit facility that matures in February 2013, with four one-year options to extend by mutual consent, and a $500 million three-year credit facility that matures in March 2013.

(in millions)	Credit Facilities


Commitment	$	2,894
Outstanding borrowings supported by credit facilities		(200	)
Outstanding letters of credit		(73	)

Amount available	$	2,621

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Debt Covenant

SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At March 31, 2011, SCE's debt to total capitalization ratio was 0.46 to 1.

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, 2011, SCE's 13-month weighted-average common equity component of total capitalization was 50.8% resulting in the capacity to pay $471 million in additional dividends.

During the first quarter of 2011, SCE made a $115 million dividend payment to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the actual level of capital expenditures, operating cash flows and earnings.

Margin and Collateral Deposits

Derivative Instruments and Power Procurement Contracts

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of March 31, 2011.

(in millions)

Collateral posted as of March 31, 2011 ¹	$	80
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade		53

Posted and potential collateral requirements for derivative instruments and power procurement contracts ²	$	133

¹: Collateral provided to counterparties and other brokers consisted of $4 million which was offset against net derivative liabilities and $76 million (consisting of $4 million in cash reflected in "Other current assets" on the consolidated balance sheets and $72 million in letters of credit).
²: Total posted and potential collateral requirements may increase by an additional $18 million, based on SCE's forward positions as of March 31, 2011, due to adverse market price movements over the remaining life of the existing power procurement contracts using a 95% confidence level.

Workers Compensation Self-Insurance Fund

SCE is self-insured for workers compensation claims. SCE assesses workers compensation claims that have been asserted and those that have been incurred but not reported to determine the probable amount of losses that should be recorded. The Department of Industrial Relations for the State of California requires companies that are self-insured for workers compensation to post collateral (in the form of cash and/or letters of credits) based on the estimated workers' compensation liability if a company's bond rating were to fall below "B." As of March 31, 2011, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $209 million for its workers compensation self-insurance plan.

Historical Consolidated Cash Flows

The table below sets forth condensed historical cash flow information for SCE.

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Condensed Consolidated Statement of Cash Flows

	Three months ended March 31,

(in millions)	2011			2010

Net cash provided by operating activities	$	672		$	313
Net cash provided by financing activities		190			305
Net cash used by investing activities		(1,066	)		(1,014	)

Net decrease in cash and cash equivalents	$	(204	)	$	(396	)

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased $359 million in the first quarter of 2011 compared to the first quarter of 2010 primarily reflecting higher net tax receipts of $104 million in 2011 compared to 2010 related to accelerated depreciation benefits and net cash inflows related to balancing account over- and under-collections. The 2011 change was also due to the timing of cash receipts and disbursements related to working capital items.

Net Cash Provided by Financing Activities

Net cash provided by financing activities for the first quarter of 2011 was $190 million consisting of the following significant events:

•: Issued $200 million of commercial paper supported by SCE's line of credit to fund interim working capital requirements.
•: Issued $125 million of 6.5% Series D preference stock.
•: Paid a $115 million dividend to Edison International.

Net cash provided by financing activities for the first quarter of 2010 was $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.
•: Issued $180 million of commercial paper supported by SCE's line of credit to fund interim working capital requirements.
•: Repaid $250 million of senior unsecured notes.
•: Paid a $100 million dividend to Edison International.

Net Cash Used by Investing Activities

Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $1.0 billion and $867 million for the three months ended March 31, 2011 and 2010, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $47 million and $49 million for the three months ended March 31, 2011 and 2010, respectively.

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Contractual Obligations and Contingencies

Contractual Obligations

For a discussion of power purchase commitments, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Third-Party Power Purchase Agreements."

Contingencies

SCE has contingencies related to the Navajo Nation Litigation, nuclear insurance and spent nuclear fuel, which are discussed in "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

Environmental Remediation

As of March 31, 2011, SCE had 24 identified material sites for remediation and recorded an estimated minimum liability of $52 million. SCE expects to recover 90% of its remediation costs at certain sites. See "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies" for further discussion.

MARKET RISK EXPOSURES

SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. SCE uses derivative instruments, as appropriate, to manage its market risks. For a further discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Edison International Notes to Consolidated Financial Statements—Note 6. Derivative and Hedging Activities" and "Note 4. Fair Value Measurements" and see "SCE: Market Risk Exposures—Commodity Price Risk" in the year-ended 2010 MD&A.

Commodity Price Risk

The fair value of outstanding derivative instruments used at SCE to mitigate its exposure to commodity price risk was a net liability of $310 million and $207 million at March 31, 2011 and December 31, 2010, respectively. For further discussion of fair value measurements and the fair value hierarchy, see "Edison International Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."

Credit Risk

Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these agreements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual agreements,

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including master netting agreements. As of March 31, 2011, the amount of balance sheet exposure as described above, by the credit ratings of SCE's counterparties, was as follows:

		March 31, 2011

(in millions)		Exposure ²		Collateral			Net Exposure

S&P Credit Rating ¹
	A or higher	$	151	$	—		$	151
	A-		14		—			14
	Not rated ³		122		(50	)		72

Total		$	287	$	(50	)	$	237

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 purchases and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheets, except for any related net accounts receivable.
³: The exposure in this category relates to two long-term power purchase agreements with special purpose entities for which the underlying power plants have yet to be constructed. Prior to the start date of power deliveries, SCE's recourse is limited to the collateral posted for damages associated with a contract termination. SCE's exposure is mitigated by regulatory treatment.

The credit risk exposure set forth in the table above is composed of $7 million of net accounts receivable and $280 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

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EDISON MISSION GROUP

RESULTS OF OPERATIONS

Results of Continuing Operations

This section discusses operating results for the three months ended March 31, 2011 and 2010. EMG's continuing operations include the coal plants, 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)		2011			2010

Competitive power generation operating revenue		$	552		$	652

Fuel			182			213
Other operation and maintenance			281			250
Depreciation and amortization			73			59
Other			—			4

Total operating expenses			536			526

Operating income			16			126
Interest and dividend income			2			20
Equity in income (loss) from unconsolidated affiliates – net			(5	)		18
Other income (expense), net			3			(1	)
Interest expense – net of amounts capitalized			(80	)		(67	)

Income (loss) from continuing operations before income taxes			(64	)		96
Income tax expense (benefit)			(46	)		25

Income (loss) from continuing operations			(18	)		71
Income (loss) from discontinued operations – net of tax			(2	)		6

Net income (loss)			(20	)		77
Less: Net (income) attributable to noncontrolling interests			—			—

Net income (loss) available for common shareholder		$	(20	)	$	77

Core Earnings ¹		$	(18	)	$	71
Non-Core Earnings (Losses)
	Discontinued Operations		(2	)		6

Total EMG GAAP Earnings (Loss)		$	(20	)	$	77

¹: See use of Non-GAAP financial measures in "Edison International Management Overview—Highlights of Operating Results."

EMG's first quarter 2011 core earnings were lower than first quarter 2010 core earnings primarily due to the following pre-tax items:

•: $32 million decrease in Midwest Generation adjusted operating income due to lower generation, lower average realized energy prices and higher operating expenses partially offset by higher capacity revenue.
•: $53 million decrease in Homer City adjusted operating income due primarily to lower generation resulting from the Unit 1 and 2 unplanned outages. Unit 1 returned to service in early April, and Unit 2 is expected to return to service during the second quarter of 2011.
•: $32 million decrease in energy trading revenues due to lower congestion revenue and power trading revenue.

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•: $32 million lower income from distributions received from the March Point and Doga projects during the first quarter of 2010, with no comparable amounts in 2011.

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 three months ended March 31, 2011 and 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

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

	Three months ended March 31,

(in millions)	2011			2010

Midwest Generation plants	$	55		$	87
Homer City plant ¹		(16	)		37
Renewable energy projects		21			10
Energy trading ¹		15			47
Big 4 projects		2			4
Sunrise		(7	)		(4	)
Doga		—			15
March Point ²		—			17
Westside projects		—			1
Other projects		4			—
Leveraged lease income		1			1
Other operating income (expense)		—			2

		75			217
Corporate administrative and general		(36	)		(38	)
Corporate depreciation and amortization		(6	)		(4	)

AOI ³	$	33		$	175

¹: Effective April 1, 2011, EMMT assigned to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. For more information, see "Edison International Management Overview—Management Overview of EMG—Homer City Outage."
²: Sold in 2010.
³: AOI is equal to operating income (loss) under GAAP, plus equity in income (loss) 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.

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

		Three months ended March 31,

(in millions)		2011			2010

AOI		$	33		$	175
Less:
	Equity in income (loss) of unconsolidated affiliates		(5	)		18
	Dividend income from projects		1			16
	Production tax credits		18			14
	Other income, net		3			1

Operating Income		$	16		$	126

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)		2011		2010

Operating Revenue		$	351	$	379
Operating Expenses
	Fuel ¹		126		141
	Plant operations		118		99
	Plant operating leases		19		19
	Depreciation and amortization		29		28
	Administrative and general		6		5

	Total operating expenses		298		292

Operating Income			53		87

Other Income			2		—

AOI		$	55	$	87

Statistics
	Generation (in GWh)		7,470		8,212

¹: Included in fuel costs were $2 million and $4 million during the quarters ended March 31, 2011 and 2010, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of NO _x emission allowances to Midwest Generation were $0.4 million during each of the first quarters of 2011 and 2010. Transfers of SO ₂ emission allowances from Midwest Generation were none and $4 million during the first quarters of 2011 and 2010, respectively. For more information regarding the price of emission allowances, see "EMG: Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

AOI from the Midwest Generation plants decreased $32 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease in AOI was attributable to lower energy revenues and higher plant operations costs, partially offset by higher capacity revenues. The decline in energy revenues was due to lower average realized energy prices and lower generation primarily related to the permanent shutdown of Will County Units 1 and 2 at the end of 2010 in accordance with the CPS.

Included in operating revenues were unrealized gains of none and $7 million for the first quarters of 2011 and 2010, respectively. Unrealized gains in 2010 were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of operations and the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at the Midwest Generation plants was

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attributable to changes in the difference between energy prices at the Northern Illinois Hub (the settlement point under forward contracts) and the energy prices at the Midwest Generation plants' busbars (the delivery point where power generated by the Midwest Generation plants is delivered into the transmission system).

Included in fuel costs were unrealized losses of $1 million and $5 million during the first quarters of 2011 and 2010, respectively, due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into in 2010 and 2009 to hedge variable fuel oil components of rail transportation costs.

Homer City

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

			Three months ended March 31,

(in millions)			2011			2010

Operating Revenue			$	115		$	175
Operating Expenses
		Fuel ¹		52			70
		Plant operations		47			37
		Plant operating leases		25			25
		Depreciation and amortization		5			5
		Administrative and general		2			1

		Total operating expenses		131			138

Operating Income (Loss)				(16	)		37

AOI			$	(16	)	$	37

Statistics
	Generation (in GWh)			1,943			2,954

¹: Included in fuel costs was less than $1 million and $4 million during the quarters ended March 31, 2011 and 2010, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of SO ₂ emission allowances to Homer City were none and $4 million during the first quarters of 2011 and 2010, respectively. Transfers of NO _x emission allowances from Homer City was less than $1 million during each of the first quarters of 2011 and 2010. For more information regarding the price of emission allowances, see "EMG: Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

AOI from the Homer City plant decreased $53 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease in AOI was attributable to lower energy revenues, driven by lower generation, and higher plant maintenance costs from unplanned outages at Units 1 and 2, partially offset by lower fuel costs. The decline in fuel costs was primarily due to lower generation, partially offset by higher coal costs.

Included in operating revenues were unrealized gains (losses) from hedge activities of $2 million and $(2) million for the first quarters of 2011 and 2010, respectively. Unrealized gains (losses) were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the statements of operations and 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 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 plant is delivered into the transmission system).

Seasonality—Coal Plants

Due to fluctuations in electric demand resulting from warm weather during the summer months and cold weather during the winter months, electric revenues from the coal plants normally vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected

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electric demand (spring and fall), further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, income from the coal plants 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 Coal Plants."

Renewable Energy Projects

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

		Three months ended March 31,

(in millions)		2011		2010

Operating Revenue		$	52	$	30
Production Tax Credits			18		14

			70		44

Operating Expenses
	Plant operations		18		12
	Depreciation and amortization		31		21
	Administrative and general		1		1

	Total operating expenses		50		34
Equity in income (losses) from unconsolidated affiliates			—		(1	)
Other Income			1		1

AOI ¹		$	21	$	10

Statistics
	Generation (in GWh) ²		1,385		843

¹: AOI is equal to operating income (loss) plus equity in income (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.
²: Includes renewable energy projects that are unconsolidated at EMG. Generation excluding unconsolidated projects was 183 GWh and 152 GWh in the first quarter of 2011 and 2010, respectively.

AOI from renewable energy projects increased $11 million in the first quarter of 2011, compared to the first quarter of 2010. The 2011 increase was primarily due to projects that achieved commercial operation in late 2010 and 2011 and increased generation at other projects due to higher availability and favorable wind conditions.

Energy Trading

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

AOI from energy trading activities decreased $32 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease was primarily attributable to lower revenues from congestion and power trading, compared to higher revenue in the first quarter of 2010.

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Adjusted Operating Income from Unconsolidated Affiliates

March Point. During the first quarter of 2010, AOI from the March Point project was $17 million due to equity distributions received from the project. EMG subsequently sold its ownership interest in the March Point project to its partner at book value in February 2010.

Doga. During the first quarter of 2010, EMG received a distribution from the Doga project. EMG expects to receive a distribution from the Doga project during the second half of 2011. AOI is recognized when cash is distributed from the project as the Doga project is accounted for on the cost method.

Seasonality. 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.

Interest Expense

		Three months ended March 31,

(in millions)		2011			2010

Interest expense, net of capitalized interest
	EME debt	$	(62	)	$	(60	)
	Non-recourse debt		(18	)		(7	)

		$	(80	)	$	(67	)

EMG's interest expense increased primarily due to higher debt balances for wind project financing, higher interest expense related to a loan amendment and lower capitalized interest. Capitalized interest for renewable energy projects under construction was $10 million for the first quarter of 2011, compared to $11 million for the first quarter of 2010.

Income Taxes

The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate.

		Three months ended March 31,

(in millions)		2011			2010

Income (loss) from continuing operations before income taxes		$	(64	)	$	96

Provision (benefit) for income tax at federal statutory rate of 35%			(22	)		34
Increase (decrease) in income tax from:
	State tax – net of federal benefit		(5	)		4
	Tax credits, net		(18	)		(15	)
	Other		(1	)		2

Total income tax expense		$	(46	)	$	25

Results of Discontinued Operations

Income from discontinued operations, net of tax, decreased $8 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease was primarily due to the expiration of a contract indemnity during the first quarter of 2010 related to EMG's previous sale of international projects.

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LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

The following table summarizes available liquidity at March 31, 2011:

(in millions)		Cash and Cash Equivalents		Available Under Credit Facilities		Total Available Liquidity


EME as a holding company		$	391	$	484	$	875
EME subsidiaries without contractual dividend restrictions			228		—		228

EME corporate cash and cash equivalents			619		484		1,103
EME subsidiaries with contractual dividend restrictions
	Midwest Generation ¹		363		497		860
	Homer City		147		—		147
	Other EME subsidiaries		54		—		54
Other EMG subsidiaries			25		—		25

Total		$	1,208	$	981	$	2,189

¹: Cash and cash equivalents are available to meet Midwest Generation's operating and capital expenditure requirements.

EME, as a holding company, does not directly own any revenue-producing generation facilities. EME relies on cash distributions and tax payments from its projects to meet its obligations, including debt service obligations on long-term debt. The timing and amount of distributions from EME's subsidiaries may be restricted. For further details, see "—Debt Covenants and Dividend Restrictions."

The following table summarizes the status of the EME and Midwest Generation credit facilities at March 31, 2011, which mature in June 2012:

(in millions)	EME			Midwest Generation


Commitments	$	564		$	500
Outstanding borrowings		—			—
Outstanding letters of credit		(80	)		(3	)

Amount available	$	484		$	497

EME and Midwest Generation may seek to extend or replace credit facilities or retire them by other means. The terms and conditions of any refinancing could be substantially different than those in the current credit facilities. Senior notes in the principal amount of $500 million, which bear interest at 7.50% per annum, are due in June 2013. EME may also from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, open market purchases, privately negotiated transactions or otherwise, depending on prevailing market conditions, EME's liquidity requirements, contractual restrictions and other factors.

For additional discussion of liquidity and the impact of Homer City's outages, see "Edison International Management Overview—Management Overview of EMG."

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Capital Investment Plan

At March 31, 2011, forecasted capital expenditures through 2013 by EMG's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

(in millions)		April through December 2011		2012		2013


Midwest Generation Plants
	Plant capital expenditures	$	23	$	21	$	28
	Environmental expenditures		82		172		317
Homer City Plant
	Plant capital expenditures		13		26		16
	Environmental expenditures		—		—		—
Renewable Energy Projects
	Capital and construction expenditures		126		—		—
	Turbine commitments		90		—		—
Other capital expenditures			11		14		14

Total		$	345	$	233	$	375

Environmental Capital Expenditures

Midwest Generation plants' environmental expenditures include $64 million for remaining expenditures in 2011 related to selective non-catalytic reduction (SNCR) equipment and $503 million for expenditures for the remainder of 2011 to 2013 to begin to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO ₂ emissions. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply remain subject to conditions applicable at the time decisions are required or made. Accordingly, the environmental expenditures for Midwest Generation in the preceding table represent current projects only and are subject to change based upon a number of considerations. Actual expenditures could be higher or lower. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to continue or complete the project. For additional discussion, see "Edison International Management Overview—Management Overview of EMG—Midwest Generation Environmental Compliance Plans and Costs."

The capital investment plan set forth in the previous table does not include environmental capital expenditures for Homer City. However, depending on upcoming and future regulatory developments, Homer City may be required to undertake capital projects to install additional pollution control equipment, which will be dependent on lessor decisions and on obtaining available funding for these expenditures. Homer City projects that if SO ₂ reduction technology becomes required, it may need to make capital commitments for such equipment several years in advance of the effective date of such requirements. Homer City continues to review technologies available to reduce SO ₂ and mercury emissions and to monitor developments related to hazardous pollutants and other environmental regulations. The timing, selection of technology and required capital costs remain uncertain. 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, and Homer City may need third-party capital to fund such activities in order to continue operating, the availability of which cannot be assured. EME has no legal obligation to provide funding. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital have not been made. For a discussion of environmental regulations, refer to "Item 1. Environmental Regulation of Edison International and Subsidiaries" and refer to "Item 1A. Risk Factors—Risks Relating to EMG—Regulatory and Environmental Risks" in the 2010 Form 10-K.

Non-Environmental Capital Expenditures

Plant capital expenditures in the preceding table relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, generator stator rewinds, condenser

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re-tubing, development of a coal-cleaning plant refuse site and a new ash disposal site, and main power transformer replacement.

Renewable energy projects' capital and construction expenditures include a project of an unconsolidated entity in which construction expenditures will be substantially funded by EMG. In addition, U.S. Treasury grants of $367 million are anticipated based on estimated eligible construction costs for renewable projects completed in 2010 and scheduled to be completed in 2011.

Future Projects

The capital investment plan set forth in the previous table does not include capital expenditures for future projects. At March 31, 2011, EMG had a development pipeline of potential wind projects with projected installed capacity of approximately 3,700 MW. The development pipeline represents potential wind projects with respect to which EMG either owns the project rights or has exclusive acquisition rights. At March 31, 2011, EMG had two wind projects totaling 160 MW under construction. In April 2011, the 55 MW Pinnacle wind project in West Virginia commenced construction. EMG anticipates that these wind projects will achieve commercial operation in 2011. The pace of additional growth in EMG's renewable program will be subject to the availability of third-party equity capital. At March 31, 2011, EMG had capitalized costs and made turbine deposits totaling $45 million related to renewable energy development efforts. To the extent that the renewable energy projects are not successful, EMG would record a charge to write down the carrying amount of these assets.

During the first quarter, EMG entered into a memorandum of understanding with AES Southland Holdings, LLC to purchase certain equipment at AES's Huntington Beach facility and lease back such equipment until decommissioned. The transaction, if consummated, would result in retirement of the equipment in late 2012 in connection with the startup of EMG's proposed Walnut Creek natural gas-fired peaker plant, thereby exempting the proposed Walnut Creek plant from 90% of the regulatory requirement for emission reduction credits needed to start construction. In April 2011, EMG entered into turbine supply and construction agreements with limited contractual obligations until such time as the remaining development activities, including final permitting, are completed. EMG intends to obtain project debt financing for this 479 MW project, which has a long-term power sales agreement with Southern California Edison Company. Completion of development is subject to a number of conditions, none of which are assured.

Historical Segment Cash Flows

The table below sets forth condensed historical cash flow information for EMG.

Condensed Statement of Cash Flows

	Three months ended March 31,

(in millions)	2011			2010

Operating cash flow from continuing operations	$	116		$	284
Operating cash flow from discontinued operations		(2	)		6

Net cash provided by operating activities		114			290
Net cash provided (used) by financing activities		103			(55	)
Net cash used by investing activities		(108	)		(99	)

Net increase in cash and cash equivalents	$	109		$	136

Net Cash Provided by Operating Activities

Cash provided by operating activities from continuing operations decreased $168 million in the first quarter of 2011 compared to the first quarter of 2010 primarily attributable to lower net income and the settlement of derivative contracts in 2010.

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Net Cash Provided by Financing Activities

Cash provided by financing activities from continuing operations increased $158 million in the first quarter of 2011 compared to the first quarter of 2010 primarily due to additional borrowing in Viento Funding II refinance and advances under the Laredo and Big Sky financing agreements. The increase also reflects a repayment of debt at Edison Funding Company in 2010.

Net Cash Provided by Investing Activities

Cash used by investing activities for the first quarters of 2011 and 2010 primarily consisted of capital expenditures. In addition, cash used by investing activities for the first quarter of 2010 included turbine deposits (investment in other assets) related to wind projects.

Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT as of March 31, 2011 were as follows:

	Moody's Rating		Fitch Rating


EME ¹	B3	B-	B-
Midwest Generation ²	Ba2	B+	BB
EMMT	Not Rated	B-	Not Rated

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

All the above ratings are on negative outlook. EMG 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. EMG 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.

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 plant through EMMT, refer to "EMG: Liquidity and Capital Resources—Credit Ratings—Credit Rating of EMMT" in the year-ended 2010 MD&A.

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

To reduce its exposure to market risk, EMG hedges a portion of its electricity price exposure through EMMT. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EMG has entered into guarantees in support of EMMT's hedging and trading activities; however, EMG has historically also 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 these hedging and trading activities. For further details, see "Edison International Notes to Consolidated Financial Statements Note 6. Derivative Instruments and Hedging Activities."

Future cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2011, if wholesale energy prices change or if EMMT enters into additional transactions. Certain

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EMMT hedge contracts do not require margin, but contain provisions that require EMG 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."

Debt Covenants and Dividend Restrictions

Credit Facility Financial Ratios

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

	Twelve months ended

(in millions)	March 31, 2011		December 31, 2010

Ratio		2.13		2.07
Covenant threshold (not less than)		1.20		1.20

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

(in millions)


Corporate-debt-to-capital ratio	0.52	0.52
Covenant threshold (not more than)	0.75	0.75

Key Ratios of EMG's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EMG's principal subsidiaries required by financing arrangements at March 31, 2011 or for the 12 months ended March 31, 2011:

Subsidiary	Financial Ratio	Covenant


Midwest Generation (Midwest Generation plants)	Debt to Capitalization Ratio	Less than or equal to 0.60 to 1	0.14 to 1
Homer City (Homer City plant)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	1.87 to 1

To pay dividends, Homer City must meet the senior rent service coverage ratio. In addition, Homer City is restricted from paying dividends until the Homer City equity reserve account is replenished. For additional information, see "Edison International Management Overview—Management Overview of EMG—Homer City Outage."

For a more detailed description of the covenants binding EMG's principal subsidiaries that may restrict the ability of those entities to make distributions to EMG directly or indirectly through the other holding companies owned by EMG, refer to "EMG: Liquidity and Capital Resources—Debt Covenants and Dividend Restrictions" in the year ended 2010 MD&A.

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

EMG is restricted under applicable agreements from selling or disposing 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, 2011, the maximum permissible sale or disposition of EMG assets was $887 million.

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Contractual Obligations and Contingencies

Fuel Supply Contracts

For a discussion of fuel supply contracts , see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments."

Midwest Generation New Source Review Lawsuit

For a discussion of the Midwest Generation New Source Review Lawsuit, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Lawsuit."

Homer City New Source Review Lawsuit

For a discussion of the Homer City New Source Review Lawsuit, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments."

Off-Balance Sheet Transactions

For a discussion of EMG's off-balance sheet transactions, refer to "EMG: Liquidity and Capital Resources—Off-Balance Sheet Transactions" in the year ended 2010 MD&A. There have been no significant developments with respect to EMG's off-balance sheet transactions that affect disclosures presented in the 2010 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 2010 MD&A.

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 costs. The following table summarizes unrealized gains (losses) from non-trading activities:

		Three months ended March 31,

(in millions)		2011			2010

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

Total unrealized gains		$	1		$	—

At March 31, 2011, cumulative unrealized gains of $5 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($(1) million for the remainder of 2011 and $6 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 4. Fair Value Measurements" and "Note 6. Derivative Instruments and Hedging Activities," respectively.

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Commodity Price Risk

Energy Price Risk Affecting Sales from the Coal Plants

Energy and capacity from the coal plants 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, and to a lesser extent, the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City plant.

The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first quarters of 2011 and 2010:

		24-Hour Average Historical Market Prices ¹

		2011		2010

Midwest Generation plants
	Northern Illinois Hub	$	34.09	$	34.53
Homer City plant
	PJM West Hub	$	45.77	$	44.53
	Homer City Busbar		41.47		39.33

¹: Energy prices were calculated at the Northern Illinois Hub and Homer City Busbar delivery points and the PJM West Hub using historical hourly real-time prices as published by PJM or provided on the PJM web-site.

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, 2011:

		24-Hour Forward Energy Prices ¹

		Northern Illinois Hub		PJM West Hub

2011
	April	$	29.53	$	40.01
	May		28.15		39.74
	June		30.92		43.44
	July		35.17		48.86
	August		37.29		50.28
	September		28.63		42.66
	October		25.17		40.65
	November		28.56		41.65
	December		30.14		45.92
2012 calendar "strip" ²		$	31.30	$	46.20

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 coal plants into these markets may vary materially from the forward market prices set forth in the preceding table.

EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services

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contracts and forward contracts accounted for on the accrual basis) at March 31, 2011 for electricity expected to be generated during the remainder of 2011 and in 2012 and 2013:

		2011				2012				2013

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

Midwest Generation plants
	Northern Illinois and AEP/Dayton Hubs		7,664	$	37.78		5,350	$	35.25		1,020	$	39.11
Homer City plant ^2,3
	PJM West Hub		1,195		58.86		1,370		51.68		204		51.85

Total			8,859				6,720				1,224

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 2011 and 2012 include hedging activities entered into by EMMT for the Homer City plant that are not designated under the intercompany agreements with Homer City due to limitations under the sale leaseback transaction documents.
³: The average price/MWh includes 182 to 191 MW of capacity for periods ranging from April 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

Capacity Price Risk

The following table summarizes the status of capacity sales for Midwest Generation and Homer City at March 31, 2011:

													Other Capacity Sales, Net of Purchases ³

									RPM Capacity Sold in Base Residual Auction				Other Capacity Sales, Net of Purchases ³
		Installed Capacity MW		Unsold Capacity ¹ MW			Capacity Sold ² MW		RPM Capacity Sold in Base Residual Auction							Average Price per MW-day		Aggregate Average Price per MW-day
		Installed Capacity MW		Unsold Capacity ¹ MW			Capacity Sold ² MW		MW		Price per MW-day		MW			Average Price per MW-day		Aggregate Average Price per MW-day

April 1, 2011 to May 31, 2011
	Midwest Generation		5,477		(548	)		4,929		4,929	$	174.29		—			—	$	174.29
	Homer City		1,884		(261	)		1,623		1,813		174.29		(190	)	$	53.95		188.38
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		(163	)		1,721		1,771		110.00		(50	)		30.00		112.32
June 1, 2012 to May 31, 2013
	Midwest Generation		5,477		(773	)		4,704		4,704		16.46		—			—		16.46
	Homer City		1,884		(232	)		1,652		1,736		133.37		(84	)		16.46		139.31
June 1, 2013 to May 31, 2014
	Midwest Generation		5,477		(827	)		4,650		4,650		27.73		—			—		27.73
	Homer City		1,884		(104	)		1,780		1,780		226.15		—			—		221.03	⁴

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: Excludes 182 to 191 MW of capacity for periods ranging from April 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.
³: 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.
⁴: Includes the impact of a 100 MW capacity swap transaction executed prior to the base residual auction at $135 per MW-day.

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The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 and June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the prices of $16.46 per MW-day and $27.73 per MW-day were substantially lower than other areas' capacity prices. The impact of lower capacity prices for these periods compared to previous years will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by an unavailability of competing resources and increased energy prices.

Basis Risk

During the three months ended March 31, 2011 and 2010, prices at the Homer City busbar were lower than the PJM West Hub by an average of 9% and 12%, respectively, due to transmission congestion in PJM. During the three months ended March 31, 2011, prices at the individual busbars of the Midwest Generation plants were lower than the AEP/Dayton Hub and Northern Illinois Hub by an average of 10% and 1%, respectively, compared to 11% and 1%, respectively, during the three months ended March 31, 2010, due to transmission congestion in PJM.

Coal and Transportation Price Risk

The Midwest Generation plants and Homer City plant 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, 2011 for the remainder of 2011 and the following two years:

	Amount of Coal Under Contract in Millions of Equivalent Tons ¹

	April through December 2011		2012		2013

Midwest Generation plants		12.4		9.8		—
Homer City plant		3.5		1.9		0.8

¹: The amount of coal under contract in equivalent 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 plant.

EMG is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which are related to the price of coal purchased for the Homer City plant, increased during 2011 from 2010 year-end prices. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO ₂ per MMBtu sulfur content) increased to a price of $76.15 per ton at April 1, 2011, compared to a price of $70 per ton at December 31, 2010, as reported by the Energy Information Administration.

Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO ₂ per MMBtu sulfur content) purchased for the Midwest Generation plants fluctuated between $13.25 per ton and $14.75 per ton during the first quarter of 2011. The market price of PRB coal decreased to a price of $13.25 per ton at April 1, 2011, compared to a price of $13.60 per ton at December 31, 2010, as reported by the Energy Information Administration.

EMG has contracts for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various short-haul carriers), which extends through December 31, 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

The federal Acid Rain Program requires electric generating stations to hold SO ₂ allowances sufficient to cover their annual emissions. Pursuant to Pennsylvania's and Illinois' implementation of the Clean Air Interstate Rule ("CAIR"), coal plants are required to hold seasonal and annual NO _x allowances.

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In the event that actual emissions required are greater than allowances held, EMG is subject to price risk for purchases of emission allowances. The market price for emission allowances may vary significantly. The average purchase price of SO ₂ allowances decreased to $10 per ton during the first quarter of 2011 from $50 per ton in 2010. The average purchase price of annual NO _x allowances decreased to $335 per ton during the first quarter of 2011 from $936 per ton in 2010. Based on broker's quotes and information from public sources, the spot price for SO ₂ allowances and annual NO _x allowances was $5 per ton and $227.50 per ton, respectively, at March 31, 2011.

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, 2011, the balance sheet exposure as described above, the credit ratings of EMG's counterparties, was as follows:

		March 31, 2010

(in millions)		Exposure ²		Collateral			Net Exposure

Credit Rating ¹
	A or higher	$	93	$	—		$	93
	A-		2		—			2
	BBB+		11		—			11
	BBB		5		—			5
	BBB-		11		—			11
	Below investment grade		48		(47	)		1

Total		$	170	$	(47	)	$	123

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 composed of $80 million of net accounts receivable and payables and $90 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 $46 million cash margin in the aggregate with PJM, 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 coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 68% of EMG's consolidated operating revenues for the three months ended March 31, 2011. At March 31, 2011, EMG's account receivable due from PJM was $55 million.

EMG's wind turbine supply agreements contain significant suppliers' obligations related to the 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 5. Debt and Credit Agreements."

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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 loss from continuing operations was $2 million and $5 million for the three months ended March 31, 2011 and 2010, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Edison International Parent liquidity and its ability to pay operating expenses and dividends to common shareholders is dependent on dividends from SCE, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capital markets.

At March 31, 2011, Edison International (parent) had approximately $26 million of cash and equivalents on hand. The following table summarizes the status of the Edison International (parent) credit facility at March 31, 2011:

(in millions)	Edison International (parent)


Commitment	$	1,426
Outstanding borrowings		(81	)
Outstanding letters of credit		—

Amount available	$	1,345

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, 2011, Edison International's consolidated debt to total capitalization ratio was 0.53 to 1.

Historical Cash Flows

The table below sets forth condensed historical cash flow information for Edison International Parent and Other.

Condensed Statement of Cash Flows

	Three months ended March 31,

(in millions)	2011			2010

Net cash used by operating activities	$	(69	)	$	(4	)
Net cash provided by financing activities		72			9
Net cash provided by investing activities		—			—

Net increase in cash and cash equivalents	$	3		$	5

Net Cash Used by Operating Activities

Net cash used by operating activities primarily relates to interest, operating costs and income taxes of Edison International (parent). In addition to these factors, Edison International funded a portion of the 2011 tax-allocation payments due by Edison Capital in consideration of an intercompany note receivable.

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Net Cash Provided (Used) by Financing Activities

Financing activities for the first quarter 2011 were as follows:

•: Paid $104 million of dividends (or $0.320 per share) to Edison International common shareholders in January of 2011. In February 2011, the Board of Directors of Edison International declared a $0.32 per share quarterly dividend which is payable in April 2011.
•: Received $115 million of dividend payments from SCE.
•: Borrowed $62 million under Edison International's line of credit to fund interim working capital requirements.

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

•: Paid $103 million of dividends (or $0.315 per share) to Edison International common shareholders.
•: Received $100 million of dividend payments from SCE.
•: Borrowed $12 million under Edison International's line of credit to fund interim working capital requirements

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EDISON INTERNATIONAL (CONSOLIDATED)

LIQUIDITY AND CAPITAL RESOURCES

Contractual Obligations

Significant changes with respect to Edison International (Consolidated) contractual obligations since the filing of the 2010 Form 10-K are discussed in "EMG: Liquidity and Capital Resources—Contractual Obligations and Contingencies" and "SCE: Liquidity and Capital Resources—Contractual Obligations and Contingencies."

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

For a discussion of Edison International's critical accounting estimates and policies, see "Critical Accounting Estimates and Policies" in the year ended 2010 MD&A.

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.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For a discussion of Edison International's legal proceedings, refer to Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies" in the 2010 Form 10-K. There have been no significant developments with respect to legal proceedings specifically affecting Edison International since the filing of the 2010 Form 10-K, except as follows:

California Coastal Commission Potential Environmental Proceeding

In May 2010, the California Coastal Commission issued an NOV to SCE, its contractor, and property owners related to activity on a property that was used for equipment storage related to a nearby SCE electricity line undergrounding construction project. The NOV alleged that SCE, through its contractor, violated the California Coastal Act by removing, without the appropriate permits, approximately one acre of vegetation from the property, which was located in a protected coastal zone within and adjacent to the City of Newport Beach, California. In late 2010, SCE tendered an indemnification claim to its contractor for liability associated with the NOV, which the contractor accepted. In the NOV, the Coastal Commission indicated an interest in negotiating a settlement of the alleged violations. The parties have reached agreement on the penalties portion of the settlement, and SCE has agreed to contribute $50,000. The parties continue to negotiate on the remaining terms of the settlement.

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Midwest Generation New Source Review Lawsuit

In March 2011, the U.S. District Court for the Northern District of Illinois dismissed nine of the ten PSD claims asserted against Midwest Generation and EME by the State of Illinois and the Department of Justice, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The Court also dismissed all claims asserted against Commonwealth Edison Company and EME. The Court denied a motion to dismiss a claim by intervenor citizens groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the Court that the statute of limitations should be equitably tolled. The Court did not address 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. Trial of the liability portion of the case is scheduled to commence on June 3, 2013.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

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


January 1, 2011 to January 31, 2011	420,521	$	38.14	—	—
February 1, 2011 to February 28, 2011	154,846	$	36.52	—	—
March 1, 2011 to March 31, 2011	687,852	$	36.66	—	—

Total	1,263,219	$	37.14	—	—

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.

ITEM 6. EXHIBITS


	10.1		Edison International 2011 Executive Annual Incentive Program
	10.2		Edison International 2011 Long-Term Incentive 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, 2011, filed on May 2, 2011, 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

*: Furnished, not filed, pursuant to Rule 406T of SEC Regulation S-T.

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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 2, 2011

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Exhibit 10.1

EDISON INTERNATIONAL
2011 Executive Annual Incentive Program

1. PURPOSE

The purpose of this Edison International 2011 Executive Annual Incentive Program (this " Program ") is to promote the success of Edison International, a California corporation, (the " Corporation "), by motivating the executives selected to participate in this Program and set forth in Section 3.1 below (each, a " Participant ") to maximize the performance of the Corporation and rewarding them with cash bonuses directly related to such performance. This Program is intended to provide bonuses that qualify as performance-based compensation within the meaning of Section 162(m) (" Section 162(m) ") of the United States Internal Revenue Code of 1986, as amended (the " Code "). This Program is adopted under Section 5.2 of the Corporation's 2007 Performance Incentive Plan (the " Plan "). Capitalized terms are defined in the Plan if not defined herein.

2. ADMINISTRATION

This Program shall be administered by the Compensation and Executive Personnel Committee of the Board (the " Committee "), which shall consist solely of two or more members of the Board who are "outside directors" within the meaning of Section 162(m). Action of the Committee with respect to the administration of this Program shall be taken pursuant to a majority vote or by the unanimous written consent of its members. The Committee shall have the authority to construe and interpret this Program and any agreements or other document relating to Awards under the Program, may adopt rules and regulations relating to the administration of this Program, and shall exercise all other duties and powers conferred on it by this Program. Any decision or action of the Committee within its authority hereunder shall be conclusive and binding upon all persons. Neither the Board nor the Committee, nor any person acting at the direction thereof, shall be liable for any act, omission, interpretation, construction or determination made in good faith in connection with this Program (or any Award made under this Program).

3. AWARDS

3.1: Award Grants; Maximum Annual Incentive Amount. Each " Award " granted to a Participant under this Program represents the opportunity to receive a cash payment determined under this Section 3 (an " Annual Incentive "), subject to the terms and conditions of this Program. The maximum amount of the Annual Incentive payable to each Participant (the " Maximum Annual Incentive Amount ") shall be determined by multiplying (i) the Annual Incentive Pool (as defined in Section 3.2 below), by (ii) the Participant's " Annual Incentive Percentage " as set forth in the following table:

Participant		Annual Incentive Percentage

Theodore F. Craver, Jr.		38%
Ronald L. Litzinger		12%
Robert L. Adler		12%
William J. Scilacci, Jr.		12%
Pedro J. Pizarro		10%
Polly L. Gault		8%
Peter T. Dietrich		8%

In no case, however, shall the amount of any Annual Incentive exceed the applicable limit set forth in Section 5.2.3 of the Plan.

3.2

Annual Incentive Pool. As soon as practicable after the end of the Corporation's 2011 fiscal year (the " Performance Period "), the Committee shall determine the amount of the Corporation's earnings from continuing operations (after interest, taxes, depreciation and amortization, and determined on a consolidated basis) for the Performance Period (the " Performance Level "). The " Annual Incentive Pool " shall be determined by multiplying (i) the Performance Level, by (ii) one and one-half percent (1.5%). No Participant shall receive any payment under this Program unless and until the Committee has certified, by resolution or other appropriate action in writing, that the amount of the Performance Level has been accurately determined in accordance with the terms, conditions and limits of this Program and that any other material terms previously established by the Committee or set forth in this Program applicable to the Award were in fact satisfied.

3.3

Committee Discretion. Notwithstanding the foregoing provisions, the Committee shall retain discretion to reduce (but not increase) the Maximum Annual Incentive Amount otherwise payable to any one or more Participants pursuant to Sections 3.1 and 3.2. The Committee may exercise such discretion on any basis it deems appropriate (including, but not limited to, its assessment of the Corporation's performance relative to its operating or strategic goals for the Performance Period and/or the Participant's individual performance for such period). For purposes of clarity, if the Committee exercises its discretion to reduce the amount of any Annual Incentive payable hereunder, it may not allocate the amount of such reduction to Annual Incentives payable to other Participants.

3.4

Payment of Annual Incentives. Any Annual Incentives shall be paid as soon as practicable following the certification of the Committee's findings under Section 3.2 and its determination of the final Annual Incentive amount (after giving effect to any exercise of its discretion to reduce Annual Incentives pursuant to Section 3.3) and in all events no later than March 15, 2012; in each case subject (i) to tax withholding pursuant to Section 4.6, and (ii) in the case of a Participant eligible to defer compensation under the EIX 2008 Executive Deferred Compensation Plan (the " EDCP "), to any timely deferral election the Participant may have made pursuant to the terms of the EDCP.

3.5

Termination of Employment.

(a): Except as provided in Section 3.5(b), in the event that a Participant's employment with the Corporation and its Subsidiaries terminates at any time during the Performance Period, the Participant's Award will immediately terminate upon such termination of employment, and the Participant will not be entitled to any Annual Incentive payment in respect of such Award; provided that the Committee may, in its discretion, award a full or partial Annual Incentive for the Performance Period to any Participant whose termination of employment during the Performance Period is due to the Participant's death, permanent and total disability, or Retirement (with the amount of any such Bonus not to exceed the amount the Participant would have been entitled to had he or she remained employed for the entire Performance Period). For purposes of this Section 3.5, the term " Retirement " with respect to a Participant shall mean a termination of the Participant's employment on or after the first day of the month in which the Participant (A) attains age 65 or (B) attains age 61 with five "years of service," as that term is defined in the Edison 401(k) Savings Plan.
(b): In the event that the Participant's employment with the Corporation and its Subsidiaries terminates during the Performance Period in circumstances that entitle the Participant to severance benefits pursuant to the Corporation's 2008 Executive Severance Plan, and in such circumstances the Participant satisfies the applicable conditions for receiving severance benefits under that plan (including, without limitation, any

requirement to execute and deliver a release of claims), then the provisions of this Section 3.5(b) shall control over Section 2.3.1(b) of the 2008 Executive Severance Plan to determine the Participant's annual incentive for the year in which such termination of employment occurs. If a Participant's Annual Incentive is to be determined pursuant to this Section 3.5(b), the Participant's Annual Incentive shall equal the lesser of (A) or (B); where (A) is determined by multiplying (i) the Participant's highest base salary rate in effect during the 24 months preceding the termination of the Participant's employment, by (ii) the highest target annual incentive percentage in effect for the Participant during those 24 months, by (iii) a fraction (not greater than 1) the numerator of which is the number of weekdays in the Performance Period from January 1, 2011 through the Participant's last day of employment prior to such termination and the denominator of which is the number of weekdays in the entire Performance Period; and (B) is determined by multiplying (i) the Participant's Annual Incentive Percentage, by (ii) one and one-half percent (1.5%), by (iii) the Corporation's earnings from continuing operations (after interest, taxes, depreciation and amortization, and determined on a consolidated basis) for the portion of the Performance Period through and ending on the last day of the month in which the Participant's termination of employment occurs. In no case, however, shall the amount of any Annual Incentive exceed the applicable limit set forth in Section 5.2.3 of the Plan.

(c): No Participant shall receive any payment under this Section 3.5 unless and until the Committee has certified, by resolution or other appropriate action in writing, the amount of the Annual Incentive due in accordance with the terms, conditions and limits of this Program. Any Annual Incentive amount due pursuant to this Section 3.5 shall be paid as soon as practicable following the Committee's certification of such amount and in all events no later than March 15, 2012; subject (i) to tax withholding pursuant to Section 4.6, and (ii) in the case of a Participant eligible to defer compensation under the EDCP, to any timely deferral election the Participant may have made pursuant to the terms of the EDCP.

3.6: Adjustments. The Committee shall adjust the Performance Level, Annual Incentive Pool and other provisions applicable to Awards granted under this Program to the extent (if any) it determines that the adjustment is necessary or advisable to preserve the intended incentives and benefits to reflect (1) any material change in corporate capitalization, any material corporate transaction (such as a reorganization, combination, separation, merger, acquisition, or any combination of the foregoing), or any complete or partial liquidation of the Corporation, (2) any change in accounting policies or practices, (3) the effects of any special charges to the Corporation's earnings, or (4) any other similar special circumstances.
3.7: Change in Control. If a Change in Control of EIX occurs at any time during the Performance Period, the Performance Period for all outstanding Awards will be shortened so that the Performance Period will be deemed to have ended on the last day prior to such Change in Control of EIX. The Annual Incentive Pool and the Annual Incentives payable with respect to each Award will be determined in accordance with the foregoing provisions of this Section 3 based on such shortened Performance Period. Such Annual Incentives shall be paid (subject to tax withholding pursuant to Section 4.6) as soon as practicable following the date of the Change in Control of EIX. For purposes of this Section 3.7, " Change in Control of EIX " shall have the meaning ascribed to such term in the Corporation's 2011 Long-Term Incentives Terms and Conditions.

4. GENERAL PROVISIONS

4.1

Rights of Participants .

(a): No Right to Continued Employment . Nothing in this Program (or in any other documents evidencing any Award under this Program) will be deemed to confer on any Participant any right to continue in the employ of the Corporation or any Subsidiary or interfere in any way with the right of the Corporation or any Subsidiary to terminate his or her employment at any time.
(b): Program Not Funded . No Participant or other person will have any right or claim to any specific funds, property or assets of the Corporation by reason of any Award hereunder. To the extent that a Participant or other person acquires a right to receive payment pursuant to any Award hereunder, such right shall be no greater than the right of any unsecured general creditor of the Corporation.

4.2

Non-Transferability of Benefits and Interests. Except as expressly provided by the Committee in accordance with the provisions of Section 162(m), all Awards are non-transferable, and no benefit payable under this Program shall be subject in any manner to sale, transfer, anticipation, alienation, assignment, pledge, encumbrance or charge. This Section 4.2 shall not apply to an assignment of a contingency or payment due (a) after the death of a Participant to the deceased Participant's legal representative or beneficiary or (b) after the disability of a Participant to the disabled Participant's personal representative.

4.3

Force and Effect. The various provisions herein are severable in their entirety. Any determination of invalidity or unenforceability of any one provision will have no effect on the continuing force and effect of the remaining provisions.

4.4

Governing Law. This Program will be construed under the laws of the State of California.

4.5

Construction.

(a): Section 162(m) . It is the intent of the Corporation that this Program, Awards and Annual Incentives paid hereunder will qualify as performance-based compensation or will otherwise be exempt from deductibility limitations under Section 162(m). Any provision, application or interpretation of this Program inconsistent with this intent to satisfy the standards in Section 162(m) shall be disregarded.
(b): Section 409A . It is the intended that Awards under this Program qualify as "short-term deferrals" within the meaning of the guidance provided by the Internal Revenue Service under Section 409A of the Code and this Program shall be interpreted consistent with that intent.

4.6

Tax Withholding. Upon the payment of any Annual Incentive, the Corporation shall have the right to deduct the amount of any federal, state or local taxes that the Corporation or any Subsidiary may be required to withhold with respect to such payment.

4.7

Amendment or Termination of Program. The Board or the Committee may at any time terminate, amend, modify or suspend this Program, in whole or in part. Notwithstanding the foregoing, no amendment may be effective without Board and/or shareholder approval if such approval is necessary to comply with the applicable rules of Section 162(m).

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Exhibit 10.1

EDISON INTERNATIONAL 2011 Executive Annual Incentive Program

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Exhibit 10.2

EDISON INTERNATIONAL
2011 Long-Term Incentives
Terms and Conditions

1. LONG-TERM INCENTIVES

The long-term incentive awards granted in 2011 (" LTI ") for eligible persons (each, a " Holder ") employed by Edison International (" EIX ") or its participating affiliates (the " Companies ", or individually, the " Company ") include the following:

•: Nonqualified stock options to purchase shares of EIX Common Stock (" EIX Options ") as described in Section 3;
•: Contingent EIX performance units (" Performance Shares ") as described in Section 4; and
•: Restricted EIX stock units (" Restricted Stock Units ") as described in Section 5.

Each of the LTI awards will be granted under the 2007 Performance Incentive Plan (the " Plan ") and will be subject to adjustment as provided in Section 7.1 of the Plan.

The LTI shall be subject to these 2011 Long-Term Incentives Terms and Conditions (these " Terms "). The LTI shall be administered by the Compensation and Executive Personnel Committee of the EIX Board of Directors (the " Committee "). The Committee shall have the administrative powers with respect to the LTI set forth in Section 3.2 of the Plan.

In the event EIX grants LTI to a Holder, the number of EIX Options, Performance Shares and Restricted Stock Units granted to the Holder will be set forth in a written award certificate delivered by EIX to the Holder.

2. VESTING OF LTI

Subject to Sections 8 and 9 the following vesting rules shall apply to the LTI:

2.1

EIX Options. The EIX Options will vest over a four-year period as described in this Section 2 (the " Vesting Period "). The effective " initial vesting date " will be January 2, 2012, or six months after the date of the grant, whichever date is later. The EIX Options will vest as follows:

•: On the initial vesting date, one-fourth of the award will vest.
•: On January 2, 2013, an additional one-fourth of the award will vest.
•: On January 2, 2014, an additional one-fourth of the award will vest.
•: On January 2, 2015, the balance of the award will vest.

2.2

Performance Shares. The Performance Shares will vest and become payable to the extent earned as determined at the end of the three-calendar-year period commencing on January 1, 2011, and ending December 31, 2013 (the " Performance Period "), subject to the provisions of Section 4.

2.3

Restricted Stock Units. The Restricted Stock Units will vest and become payable on January 2, 2014.

2.4

Continuance of Employment/Service Required. The vesting schedule requires continued employment or service through each applicable vesting date as a condition for the vesting of the applicable installment of the LTI and the rights and benefits thereunder. Employment or service for only a portion of the vesting period, even if a substantial portion, will not entitle the Holder to any proportionate vesting or avoid or mitigate a termination of rights and benefits upon or following a termination of employment or services except as provided in Sections 8 and 9 below.

3. EIX OPTIONS

3.1: Exercise Price. The exercise price of an EIX Option stated in the award certificate is the closing price (in regular trading) of a share of EIX Common Stock on the New York Stock Exchange for the effective date of the grant.
3.2: Cumulative Exercisability; Term of Option. The vested portions of the EIX Options will accumulate to the extent not exercised, and be exercisable by the Holder subject to the provisions of this Section 3 and Sections 8 and 9, in whole or in part, in any subsequent period but not later than January 2, 2021.
3.3: Method of Exercise. The Holder may exercise an EIX Option by providing written notice to EIX on the form prescribed by the Committee for this purpose, or completion of such other EIX Option exercise procedures as EIX may prescribe, accompanied by full payment of the applicable exercise price. Payment must be in cash or its equivalent acceptable to EIX. At the discretion of the Holder, EIX Common Stock valued on the exercise date at a per-share price equal to the closing price of EIX Common Stock on the New York Stock Exchange may be used to pay the exercise price, provided the Company can comply with any legal requirements. A broker-assisted "cashless" exercise may be accommodated for EIX Options at the discretion of EIX. Until payment is accepted, the Holder will have no rights in the optioned stock. The provisions of Section 10 must be satisfied as a condition precedent to the effectiveness of any purported exercise.

4. PERFORMANCE SHARES

4.1: Performance Shares. Performance Shares are EIX Common Stock-based units subject to a performance measure based on the percentile ranking of EIX total shareholder return (" TSR ") among the TSRs for the stocks comprising the Comparison Group (as defined below) over the entire Performance Period. TSR is calculated using (i) the average closing stock price for the relevant stock for the 20-trading-day period ending with the last day on which the New York Stock Exchange is open for trading preceding the first day of the Performance Period, and (ii) the average closing stock price for the relevant stock for the 20-trading-day period ending with the measurement date. A target number of contingent Performance Shares will be awarded on the initial grant date. The target number of contingent Performance Shares will be increased by any additional Performance Shares created by "reinvestment" of dividend equivalents as provided in Section 4.4. The actual amount of Performance Shares to be paid will depend on EIX's TSR percentile ranking on the measurement date. If EIX's TSR is below the 40 ^th percentile, no Performance Shares will be paid. Twenty-five percent (25%) of the target number of Performance Shares will be paid if EIX's TSR percentile ranking is at the 40 ^th percentile. The target number of Performance Shares will be paid if EIX's TSR rank is at the 50 ^th percentile. Two times the target number of Performance Shares will be paid if EIX's TSR percentile ranking is at the 75th percentile or higher. The payment multiple is interpolated for performance between the points indicated in the preceding three sentences on a straight-line basis.

The " Comparison Group " consists of the stocks comprising the Philadelphia Utility Index as the index is constituted on the measurement date, but deleting AES Corporation and adding Sempra Energy (in each case, if such stock is publicly traded on the measurement date), and adjusted as described below if there are less than 20 companies in such index as so adjusted on the measurement date. If the Comparison Group consists of less than 20 stocks on the measurement date, the stock with the median TSR for the entire Performance Period (or, if there are an even number of stocks in the Comparison Group before giving effect to this sentence, a stock deemed to have a TSR equal to the average TSR of the two stocks in the Comparison Group that fall in the middle of such group when ranked based on TSR for the entire Performance Period) shall be added back to the Comparison Group a sufficient number of times to bring the stocks comprising the Comparison Group to 20. (For purposes of clarity, if there are only 17 stocks in the Comparison Group before giving effect to the preceding sentence, the stock with the median TSR for the entire Performance Period will be added back to the Comparison Group a total of three times to bring the stocks comprising the Comparison Group to 20.)

4.2: Measurement Date. The performance measurement date will be the last day of the Performance Period on which the New York Stock Exchange is open for trading. As of that date, the applicable payment multiple will be determined as provided in Section 4.1 above based on the EIX TSR percentile ranking achieved during the Performance Period. No payment will be made with respect to the Performance Shares unless and until the Committee has certified, by resolution or other appropriate action in writing, that the applicable EIX TSR percentile ranking has been accurately determined. The Committee shall not have discretion to pay Performance Shares if the minimum EIX TSR ranking is not achieved or to pay Performance Shares in excess of the amount provided in Section 4.1 for the applicable EIX TSR ranking.
4.3: Payment of Performance Shares. Fifty percent of the Performance Shares that are earned pursuant to Section 4.1 (plus any fractional shares) will be paid in cash. The remainder of the Performance Shares earned will be paid on a one-for-one basis in EIX Common Stock under the Plan. The value of each Performance Share paid in cash will be equal to the closing price per share of EIX Common Stock on the New York Stock Exchange for the measurement date. The cash and stock payable for the earned Performance Shares will be delivered as soon as practicable for EIX following the Committee's certification in Section 4.2 above, and in all events no later than March 15, 2014. The Performance Shares are subject to termination and other conditions specified in Sections 8 and 9, and to the provisions of Section 10.
4.4: Dividend Equivalent Reinvestment. For each dividend on EIX Common Stock for which the ex-dividend date falls within the Performance Period, the Holder of Performance Shares will be credited with an additional number of target Performance Shares. The additional number of shares added on each ex-dividend date will be equal to (i) the per-share cash dividend paid by EIX on its Common Stock with respect to the related ex-dividend date, multiplied by (ii) the Holder's number of target Performance Shares (including any additional target Performance Shares previously credited under this Section 4.4), divided by (iii) the closing price of a share of EIX Common Stock on the related ex-dividend date, with the result rounded to four decimal places. Any target Performance Shares added pursuant to the foregoing provisions of this Section 4.4 will be subject to the same vesting, payment, termination and other terms, conditions and restrictions as the original target Performance Shares to which they relate (including application of the TSR payment multiple as contemplated by Section 4.1). No target Performance Shares will be added pursuant to this Section 4.4 with respect to any target Performance Shares which, as of the related ex-dividend date, have either become payable pursuant to Section 4.3 or terminated pursuant to Section 8.

5. RESTRICTED STOCK UNITS

5.1: Restricted Stock Units. Restricted Stock Units are EIX Common Stock-based units that vest based on the passage of time. As soon as practicable for EIX following January 2, 2014 (and in all events within 90 days after such date), EIX will deliver to the Holder a number of shares of EIX Common Stock equal to the number of Restricted Stock Units that have vested, except that if the Restricted Stock Units vest pursuant to Section 8.3, 8.4, 8.5 or 9, the Restricted Stock Units will become payable as provided in the applicable section below. The Restricted Stock Units are subject to termination and other conditions specified in Sections 8 and 9, and to the provisions of Section 10.

5.2: Dividend Equivalent Reinvestment. For each dividend declared on EIX Common Stock with an ex-dividend date on or after the date an award of Restricted Stock Units is granted and before all of such Restricted Stock Units either have become payable pursuant to Section 5.1 or have terminated pursuant to Section 8 or 9, the Holder of such award will be credited with an additional number of Restricted Stock Units equal to (i) the per-share cash dividend paid by EIX on its Common Stock with respect to the related ex-dividend date, multiplied by (ii) the total number of outstanding and unpaid Restricted Stock Units (including any Restricted Stock Units previously credited under this Section 5.2) subject to such award as of such ex-dividend date, divided by (iii) the closing price of a share of EIX Common Stock on the related ex-dividend date, with the result rounded to four decimal places. Any additional Restricted Stock Units credited pursuant to the foregoing provisions of this Section 5.2 will be subject to the same vesting, payment, termination and other terms, conditions and restrictions as the original Restricted Stock Units to which they relate; provided, however, that the Committee shall retain discretion to pay any Restricted Stock Units in cash rather than shares of EIX Common Stock if and to the extent that payment in shares would exceed the applicable share limits of the Plan, with any fractional shares to be paid in cash. No crediting of Restricted Stock Units will be made pursuant to this Section 5.2 with respect to any Restricted Stock Units which, as of the related ex-dividend date, have either been paid pursuant to Section 5.1 or terminated pursuant to Section 8 or 9.

6. DELAYED PAYMENT OR DELIVERY OF LTI GAINS

Notwithstanding any other provision herein, Holders who are eligible to defer salary under the EIX 2008 Executive Deferred Compensation Plan (the " EDCP ") may irrevocably elect to defer receipt of all or a part of the cash payable in respect of the portion of earned Performance Shares that are payable in cash pursuant to the terms of the EDCP. To make such an election, the Holder must submit a signed agreement in the form approved by, and in advance of the applicable deadline established by, the Committee. In the event of any timely deferral election, the LTI with respect to which the deferral election was made shall be paid in accordance with the terms of the EDCP.

7. TRANSFER AND BENEFICIARY

7.1: Limitations on Transfers. Except as provided below and in Section 10, the LTI will not be transferable by the Holder and, during the lifetime of the Holder, the LTI will be exercisable only by him or her. The Holder may designate a beneficiary who, upon the death of the Holder, will be entitled to exercise the then vested portion of the LTI during the remaining term subject to the provisions of the Plan and these Terms.
7.2: Exceptions. Notwithstanding the foregoing, the LTI of the CEOs of EIX, Edison Mission Group Inc., and Southern California Edison Company, and the EVPs of EIX, are transferable to a spouse, children or grandchildren, or trusts or other vehicles established exclusively for their benefit. Any transfer request must specifically be authorized by EIX in writing and shall be subject to any conditions, restrictions or requirements as the Committee may determine. Restricted Stock Units may not, however, be transferred to the extent the transfer would violate (and result in any tax, penalty or interest under) Section 409A of the Internal Revenue Code of 1986, as amended (the " Code ").

8. TERMINATION OF EMPLOYMENT

8.1

General. In the event of termination of the employment of the Holder for any reason other than those specified in Sections 8.2, 8.3, 8.4 or 9, the LTI will terminate as follows: (i) the Holder's unvested EIX Options will terminate for no value on the date such employment terminates, (ii) the Holder's vested EIX Options will terminate for no value 180 days from the date on which such employment terminated (or, if earlier, on the last day of the applicable EIX Option term) to the extent not theretofore exercised, (iii) the Holder's unearned Performance Shares will terminate for no value, and (iv) the Holder's unvested Restricted Stock Units will terminate for no value. Any fractional vested EIX Options will be rounded up to the next whole share.

8.2

Retirement. If the Holder terminates employment on or after the first day of the month in which he or she (i) attains age 65 or (ii) attains age 61 with five "years of service," as that term is defined in the Edison 401(k) Savings Plan (a " Retirement "), then the vesting and exercise or payment provisions of this Section 8.2 will apply.

(A): EIX Options . The EIX Options will vest; provided, however, that in the event the Holder's Retirement occurs within the calendar year in which the applicable EIX Option is granted, the portion of the option that vests upon the Holder's Retirement will be prorated by multiplying the total number of shares subject to the option by a fraction, the numerator of which shall be the number of whole months in the calendar year of grant that the Holder was employed by one or more of the Companies, and the denominator of which shall be twelve (12). In no event shall the Holder be credited with services performed during any portion of a calendar month (even if a substantial portion) if the Holder is not employed by one of the Companies as of the last day of such calendar month. The portion of the option not eligible to vest following the Holder's Retirement after giving effect to the proration described in the preceding two sentences shall terminate upon the Holder's Retirement, and the Holder shall have no further rights with respect to such terminated portion. Any fractional EIX Options vested under this Section 8.2 will be rounded up to the next whole number. Although vested upon Retirement, the options will become exercisable on the schedule under which they would have been vested had the Holder not retired (one-fourth of the option grant on the effective initial vesting date (January 2, 2012 or six months after the date of grant, whichever is later) and an additional one-fourth on January 2, 2013, 2014 and 2015), except that if the Holder dies, the then-outstanding portion of the option will be immediately exercisable as of the date of the Holder's death. In the event prorated vesting is required in connection with the Holder's Retirement, the portion of the option that does vest will become exercisable first on the effective initial vesting date (up to the maximum number of shares that would have become exercisable on that date had no termination of employment occurred) and so on until the vested portion of the option becomes exercisable, except that if the Holder dies, the then-outstanding portion of the option will be immediately exercisable as of the date of the Holder's death. Once exercisable, EIX Options will remain exercisable as provided in Section 3 for the remainder of the original EIX Option term.
(B): Performance Shares . The Performance Shares will vest and become payable at the end of the Performance Period to the extent they would have vested and become payable if the Holder's employment had continued through the last day of the Performance Period; provided, however, that if the Holder's Retirement occurs within the calendar year in which the applicable Performance Shares are granted, the portion of the Performance Shares that will vest and become payable will equal (i) the portion that would have vested and become payable if the Holder's employment had continued through the last day of the Performance Period, multiplied by (ii) a fraction, the numerator of which shall be the number of whole months in the calendar year of grant that the Holder was employed by one or more of the Companies, and the denominator of which shall be twelve (12), with the result rounded to four decimal places. For this purpose, the number of "whole months" shall be calculated as provided in Section 8.2(A) above. Performance Shares will be payable to the Holder on the payment date specified in Section 4.3 to the extent of the EIX TSR ranking achieved as specified in Section 4.1. Any fractional Performance Shares vested under this Section 8.2(B) will be paid in cash. Any unvested Performance Shares (after application of the foregoing vesting provisions) will terminate for no value.

(C): Restricted Stock Units . The Restricted Stock Units will vest upon the Holder's Retirement and will be payable on or as soon as practicable for EIX following January 2, 2014 (and in all events within 90 days after such date); provided, however, that in the event the Holder's termination of employment occurs within the calendar year in which the applicable Restricted Stock Unit award is granted, the number of Restricted Stock Units that vests upon the Holder's Retirement will be prorated by multiplying the total number of Restricted Stock Units subject to the award by a fraction, the numerator of which shall be the number of whole months in the calendar year of grant that the Holder was employed by one or more of the Companies, and the denominator of which shall be twelve (12), with the result rounded to four decimal places. In no event shall the Holder be credited with services performed during any portion of a calendar month (even if a substantial portion) if the Holder is not employed by one of the Companies as of the last day of such calendar month. Any fractional Restricted Stock Units vested under this Section 8.2(C) will be paid in cash. Any unvested Restricted Stock Units (after application of the foregoing vesting provisions) will terminate for no value. Notwithstanding the foregoing provisions, if the Holder dies after Retirement and prior to the date the vested Restricted Stock Units are paid, the vested Restricted Stock Units will be paid as soon as practicable for EIX (and in all events within 90 days) following the date of the Holder's death.

8.3

Death or Disability. If, prior to the Holder's termination of employment with a Company, the Holder dies or incurs a "disability" (as such term is defined for purposes of Section 409A of the Code), the provisions of this Section 8.3 will apply.

(A): EIX Options . Any unvested EIX Options will immediately vest. The EIX Options will be exercisable immediately as of the date of such termination and will remain exercisable as provided in Section 3 for the remainder of the original EIX Option term.
(B): Performance Shares . The Performance Shares will vest and become payable at the end of the Performance Period as provided in Section 4.3 to the extent they would have vested and become payable if the Holder's employment had continued through the last day of the Performance Period.
(C): Restricted Stock Units . Any unvested Restricted Stock Units will immediately vest and become payable as soon as practicable for EIX (and in all events within 90 days) after the date of the Holder's death or disability, as applicable.

8.4

Involuntary Termination Not for Cause. Except as may otherwise be provided in Section 9, upon involuntary termination of the Holder's employment by his or her employer not for cause (and other than due to the Holder's death or disability), the provisions of this Section 8.4 shall apply.

(A): EIX Options . Unvested EIX Options will vest to the extent necessary to cause the aggregate number of shares subject to vested EIX Options (including any shares acquired pursuant to previously exercised EIX Options) to equal the number of shares granted multiplied by a fraction (not greater than 1), the numerator of which is the number of weekdays in the period from January 1 of the year of grant of the award through the one-year anniversary of the Holder's last day of employment prior to termination of the Holder's employment, and the denominator of which is the number of weekdays in the four calendar years 2011-2014. The Holder will have one year following the date of termination in which to exercise the EIX Options, or until the end of the EIX Option term, whichever occurs earlier. The Holder's vested options will terminate for no value at the end of such period to the extent not theretofore exercised. The portion of the option not eligible to vest following the termination of the Holder's employment after giving effect to the proration described in this Section 8.4(A) shall terminate upon the termination of the Holder's employment, and the Holder shall have no further rights with respect to such terminated portion. Any fractional EIX Options vested under this Section 8.4(A) will be rounded up to the next whole number.

Notwithstanding anything to the contrary in the preceding paragraph, if the Holder qualifies for Retirement (as defined in Section 8.2) at the time of the termination of the Holder's employment, or if the Holder would have satisfied the requirements for Retirement if an extra year of service and age were applied, EIX Options will (i) vest (without any proration), (ii) become exercisable on the schedule specified in Section 8.2 and (iii) remain exercisable for the remainder of the original EIX Option term.

(B): Performance Shares . The Performance Shares will vest with respect to (i) the number of Performance Shares that would have vested and become payable if the Holder's employment had continued through the last day of the Performance Period, multiplied by (ii) a fraction (not greater than 1), the numerator of which is the number of weekdays the Holder was employed by EIX or a subsidiary from January 1 of the year of grant of the award through the one-year anniversary of the Holder's last day of employment prior to termination of the Holder's employment, and the denominator of which is the number of weekdays in the three calendar years 2011-2013. Such vested Performance Shares will be payable to the Holder as provided in Section 4.3 to the extent of the EIX TSR ranking achieved as provided in Section 4.1. Any fractional Performance Shares vested under this Section 8.4(B) will be rounded up to the next whole number. Any unvested Performance Shares (after application of the foregoing vesting provisions) will terminate for no value as of the date of the Holder's termination of employment.

Notwithstanding anything to the contrary in the preceding paragraph, if the Holder qualifies for Retirement (as defined in Section 8.2) at the time of the termination of the Holder's employment, or if the Holder would have satisfied the requirements for Retirement if an extra year of service and age were applied, the Performance Shares will vest (without proration) and become payable at the end of the Performance Period as provided in Section 4.3 to the extent they would have vested and become payable if the Holder's employment had continued through the last day of the Performance Period.

(C): Restricted Stock Units . The Restricted Stock Units will vest to the extent necessary to cause the aggregate number of vested Restricted Stock Units to equal the number of Restricted Stock Units subject to the award multiplied by a fraction (not greater than 1), the numerator of which is the number of weekdays in the period from January 1 of the year of grant of the award through the one-year anniversary of the Holder's last day of employment prior to termination of the Holder's employment, and the denominator of which is the number of weekdays in the three calendar years 2011-2013. Any fractional Restricted Stock Units vested under this Section 8.4(C) will be rounded up to the next whole number. Any unvested Restricted Stock Units (after

application of the foregoing vesting provisions) will terminate for no value as of the date of the Holder's termination of employment. Vested Restricted Stock Units will be paid as soon as practicable for EIX (and in all events within 90 days) following the date of the Holder's Separation from Service, if the Separation from Service occurs prior to any other applicable payment event otherwise provided for in these Terms. For purposes of the LTI, a " Separation from Service " means the Holder's "separation from service" with the Company as that term is used for purposes of Section 409A of the Code.

Notwithstanding anything to the contrary in the preceding paragraph, if the Holder qualifies for Retirement (as defined in Section 8.2) at the time of the termination of the Holder's employment, the Restricted Stock Units will vest (without any proration) and become payable at the same time provided for in Section 8.2(C). In addition, and notwithstanding anything to the contrary in the preceding paragraph, if the Holder would have satisfied the requirements for Retirement at the time of the termination of the Holder's employment if an extra year of service and age were applied, the Restricted Stock Units will vest (without any proration) and become payable as soon as practicable for EIX (and in all events within 90 days) following the date of the Holder's Separation from Service, if the Separation from Service occurs prior to any other applicable payment event otherwise provided for in these Terms.

(D): Conditions of Benefits . Notwithstanding the foregoing provisions, if at the time of the Holder's involuntary termination the Holder is covered by a severance plan of EIX or any of its affiliates, the Holder shall be entitled to the accelerated vesting provided in this Section 8.4 only if the Holder satisfies the applicable conditions for receiving severance benefits under that plan (including, without limitation, any requirement to execute and deliver a release of claims) in connection with such involuntary termination. In the event that such conditions are not satisfied, the provisions of Section 8.1 above shall apply, and the Holder shall not be entitled to any accelerated vesting under this Section 8.4.

8.5: Effect of Change of Employer. For purposes of the LTI only, involuntary termination of employment will be deemed to occur on the date the Holder's employing company is no longer a member of the EIX controlled group of corporations as defined in Section 1563(a) of the Code, regardless of whether the Holder's employment continues with that entity or a successor entity outside of the EIX controlled group. A termination of employment will not be deemed to occur for purposes of the LTI if a Holder's employment by one EIX Company terminates but immediately thereafter the Holder is employed by another EIX Company.

9. CHANGE IN CONTROL; EARLY TERMINATION OF LTI

Notwithstanding any other provision herein, in the event of a Change in Control of EIX (as defined in Section 9.6), the provisions of this Section 9 will apply.

9.1: EIX Options. In the event the EIX Options are to terminate pursuant to Section 7.2 of the Plan in connection with a Change in Control of EIX, then upon (or, as may be necessary to effect the acceleration, immediately prior to) the Change in Control of EIX the then-outstanding and unvested EIX Options will become fully vested; provided, however, that this automatic acceleration provision will not apply with respect to any EIX Options to the extent the Committee has made a provision for the substitution, assumption, exchange or other continuation of the EIX Options. In the event of such a termination where the Committee has not provided for a cash settlement of the EIX Options as described below, the Holder of each EIX Option that is to be so terminated will be given reasonable advance notice of the impending termination and a reasonable opportunity to exercise such EIX Option in accordance with its terms before such termination (except that in no event will more than 10 days' notice of the accelerated vesting and impending termination be required). The Committee may provide, as to each EIX Option that is to be terminated in connection with a Change in Control of EIX, to settle the EIX Option by a cash payment to the Holder of such option based upon the distribution or consideration payable to the holders of the EIX Common Stock upon or in respect of such event, such cash payment to be made as soon as practicable for EIX after the Change in Control of EIX.

9.2: Performance Shares. In the event the Performance Shares are to terminate pursuant to Section 7.2 of the Plan in connection with a Change in Control of EIX, then the Performance Period for all outstanding Performance Shares will be shortened so that the Performance Period will be deemed to have ended on the last day prior to such Change in Control of EIX, and the Performance Shares that will vest and become payable will be determined in accordance with Section 4.1 based on such shortened Performance Period; provided, however, that this automatic acceleration provision will not apply with respect to any Performance Shares to the extent the Committee has made a provision for the substitution, assumption, exchange or other continuation of the Performance Shares. Any Performance Shares that become subject to a shortened Performance Period pursuant to this Section 9.2 shall be paid, to the extent such Performance Shares become vested and payable after giving effect to the first sentence of this Section 9.2, to the Holder in cash as soon as practicable for EIX (and in all events within 74 days) after the date of the Change in Control of EIX, and any such Performance Shares that do not become vested and payable shall terminate for no value as of the date of the Change in Control of EIX.
9.3: Restricted Stock Units. This Section 9.3 applies to the Restricted Stock Units notwithstanding anything to the contrary in Section 7.2 of the Plan. The Committee may not exercise any discretion to change the payment date(s) of the Restricted Stock Units except as otherwise expressly provided in this Section 9.3 or as otherwise compliant with (so as to not result in any tax, penalty or interest under) Section 409A of the Code. The Restricted Stock Units may only be terminated in connection with a Change in Control of EIX to the extent the termination satisfies the requirements of Treasury Regulation Section 1.409A-3(j)(4)(ix) (Plan Terminations and Liquidations). In the event the Restricted Stock Units are to terminate in connection with such an event, then upon (or, as may be necessary to effect the acceleration, immediately prior to) the Change in Control of EIX, the then-outstanding and unvested Restricted Stock Units will become fully vested. In the event the Restricted Stock Units are not to be so terminated in connection with such an event, the Committee shall make provision for the substitution, assumption, exchange or other continuation of the Restricted Stock Units in a manner that is compliant with (and does not result in any tax, penalty or interest under) Section 409A of the Code and the Restricted Stock Units shall be paid at the first applicable time otherwise provided in these Terms.
9.4: Severance Plan Benefits. If a Holder is a participant in the EIX 2008 Executive Severance Plan (or any similar successor plan) and experiences a Qualifying Termination Event as defined in the EIX 2008 Executive Severance Plan (or a similar employment termination under a successor plan) associated with a Change in Control as defined in the EIX 2008 Executive Severance Plan (or any similar successor plan), then (i) the Holder's outstanding EIX Options will immediately vest, (ii) the Holder will have two years following the date of termination in which to exercise such EIX options if the Holder is a Senior Vice President, President or other officer designated by the Chief Executive Officer of EIX to be in Executive Compensation Band D or above (three years if the Holder is the Chief Executive Officer of EIX, Southern California Edison Company, or Edison Mission Group Inc., or the General Counsel or Chief Financial Officer of EIX), in each case subject to earlier termination at the end of the applicable option term or as provided in Section 9.1 above, (iii) any then outstanding Performance Shares shall be treated as provided for in Section 8.3(B) above, if the applicable performance period has not been shortened pursuant to Section 9.2 above, and (iv) any then outstanding Restricted Stock Units shall vest in accordance with Section 8.3(C) above, if vesting had not otherwise been triggered by Section 9.3 above, and shall be paid at the time determined in accordance with Section 8.4(C).

9.5

Other Acceleration Rules. Any acceleration of LTI pursuant to this Section 9 will comply with applicable legal requirements and, if necessary to accomplish the purposes of the acceleration or if the circumstances require, may be deemed by the Committee to occur within a limited period of time not greater than 30 days prior to the Change in Control of EIX. Without limiting the generality of the foregoing, the Committee may deem an acceleration to occur immediately prior to the applicable event and/or reinstate the original terms of a LTI if the event giving rise to acceleration does not occur.

9.6

Definition of Change in Control of EIX. A " Change in Control of EIX " shall be deemed to have occurred as of the first day, after the date of grant, that any one or more of the following conditions shall have been satisfied:

(A)

Any Person (other than a trustee or other fiduciary holding securities under an employee benefit plan of EIX) becomes the Beneficial Owner, directly or indirectly, of securities of EIX representing thirty percent (30%) or more of the combined voting power of EIX's then outstanding securities. For purposes of this clause, " Person " shall mean any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act, except that such term shall not include one or more underwriters acquiring newly-issued voting securities (or securities convertible into voting securities) directly from EIX with a view towards distribution; and the term " Beneficial Owner " shall mean as defined under Rule 13d-3 promulgated under the Exchange Act.

(B)

On any day after the date of grant (the " Reference Date ") Continuing Directors cease for any reason to constitute a majority of the Board. A director is a " Continuing Director " if he or she either:

(i): was a member of the Board on the applicable Initial Date (an " Initial Director "); or
(ii): was elected to the Board, or was nominated for election by EIX's shareholders, by a vote of at least two-thirds (2/3) of the Initial Directors then in office.

A member of the Board who was not a director on the applicable Initial Date shall be deemed to be an Initial Director for purposes of clause (b) above if his or her election, or nomination for election by EIX's shareholders, was approved by a vote of at least two-thirds (2/3) of the Initial Directors (including directors elected after the applicable Initial Date who are deemed to be Initial Directors by application of this provision) then in office. For these purposes, " Initial Date " means the later of (A) the date of grant or (B) the date that is two (2) years before the Reference Date.

(C): EIX is liquidated; all or substantially all of EIX's assets are sold in one or a series of related transactions; or EIX is merged, consolidated, or reorganized with or involving any other corporation, other than a merger, consolidation, or reorganization that results in the voting securities of EIX outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) more than fifty percent (50%) of the combined voting power of the voting securities of EIX (or such surviving entity) outstanding immediately after such merger, consolidation, or reorganization. Notwithstanding the foregoing, a bankruptcy of EIX or a sale or spin-off of an affiliate of EIX (short of a dissolution of EIX or a liquidation of substantially all of EIX's assets, determined on an aggregate basis) will not constitute a Change in Control of EIX.
(D): The consummation of such other transaction that the Board may, in its discretion in the circumstances, declare to be a Change in Control of EIX for purposes of the Plan.

10. TAXES AND OTHER WITHHOLDING

Upon any exercise, vesting, or payment of any LTI, the Company shall have the right at its option to:

•: require the Holder (or the Holder's personal representative or beneficiary, as the case may be) to pay or provide for payment of at least the minimum amount of any taxes which the Company may be required to withhold with respect to such LTI event or payment; or
•: deduct from any amount otherwise payable in cash to the Holder (or the Holder's personal representative or beneficiary, as the case may be) the minimum amount of any taxes which the Company may be required to withhold with respect to such cash payment.

To the extent that the payment of any LTI pursuant to exercise or vesting requires tax withholding and a sufficient amount of cash (not otherwise deferred) is not generated from the underlying transaction to satisfy such withholding obligations, EIX shall (except as provided below) substitute a cash award for a number of shares of Common Stock otherwise issuable pursuant to the LTI, rounded up to the next whole share for fractional shares, valued in a consistent manner at their fair market value as of the date of such exercise or vesting, necessary to satisfy the minimum applicable withholding obligation in connection with such transaction to the extent that such withholding amount exceeds the amount of cash generated from the underlying transaction and not otherwise deferred. In no event shall the shares withheld exceed the minimum whole number of shares required for tax withholding under applicable law. If for any reason EIX cannot or elects not to satisfy such withholding obligations in such manner, or if a tax withholding obligation arises in any other circumstances, the Company shall have the right to satisfy such withholding obligations, or require the Holder to satisfy such withholding obligations, as otherwise provided above.

To the extent that the payment of any LTI pursuant to exercise or vesting requires Garnishment Payments by the Company, and a sufficient amount of cash is not generated by the underlying transaction to satisfy the Garnishment Payment obligations arising from such transaction, the Company shall substitute a cash award for a number of shares of Common Stock otherwise issuable pursuant to the LTI, rounded up to the next whole share for fractional shares, having a fair market value on the date of exercise or vesting equal to the amount required by any Garnishment, less any cash received and not deferred in connection with such transaction. For this purpose, " Garnishment " means garnishment orders, levies, and other assessments imposed by legal authority and " Garnishment Payments " means payments required by the Company pursuant to any such Garnishment.

11. CONTINUED EMPLOYMENT

Nothing in the award certificate or these Terms will be deemed to confer on the Holder any right to continue in the employ of any Company or interfere in any way with the right of the Companies to terminate his or her employment at any time.

12. INSIDER TRADING; SECTION 16

12.1: Insider Trading. Each Holder shall comply with all EIX notice, trading and other policies regarding transactions in and involving EIX securities (including, without limitation, policies prohibiting insider trading).
12.2: Section 16. If an LTI is granted to a person who later becomes subject to the provisions of Section 16 of the Exchange Act (" Section 16 ") in respect of EIX, the LTI will immediately and automatically become subject to the requirements of Rule 16b-3(d) and/or 16b-3(e) (the " Rule ") and may not be exercised, paid or transferred until the Rule has been satisfied. In its sole discretion, the Committee may take any action to assure compliance with the requirements of the Rule, including withholding delivery to Holder (or any other person) of any security or of any other payment in any form until the requirements of the Rule have been satisfied. The Secretary of EIX may waive compliance with the requirements of the Rule if he or she determines the transaction to be exempt from the provisions of paragraph (b) of Section 16.
12.3: Notice of Disposition. The Holder agrees that if he or she should plan to dispose of any shares of stock acquired on the exercise or payment of LTI awards (including a disposition by sale, exchange, gift or transfer of legal title) and the Holder is a person who is required to preclear EIX securities transactions, the Holder will notify EIX prior to such disposition.

13. AMENDMENT

The LTI are subject to the terms of the Plan, as it may be amended from time to time. EIX reserves the right to amend these Terms from time to time to the extent that EIX reasonably determines that the amendment is necessary or advisable to comply with applicable laws, rules or regulations or to preserve the intended tax consequences of the applicable LTI. The LTI may not otherwise be amended or terminated (by amendment to or of the Plan or otherwise) in any manner materially adverse to the rights of the Holder of the affected LTI without such Holder's consent.

14. MISCELLANEOUS

14.1: Force and Effect. The various provisions herein are severable in their entirety. Any determination of invalidity or unenforceability of any one provision will have no effect on the continuing force and effect of the remaining provisions.
14.2: Governing Law. These Terms will be construed under the laws of the State of California.
14.3: Notice. Unless waived by EIX, any notice required under or relating to the LTI must be in writing, with postage prepaid, addressed to: Edison International, Attn: Corporate Secretary, P.O. Box 800, Rosemead, CA 91770.
14.4: Construction. These Terms shall be construed and interpreted to comply with Section 409A of the Code. Additionally, when any provision of this document refers to a date, including a date implied by the end of a specified period, and that date falls on a holiday or weekend, the date shall be deemed to be the next succeeding business day, except that the last day of the Performance Period shall occur on December 31, 2013 and in no event shall the term of an EIX Option extend beyond its maximum 10-year term. Any determination of trading price or fair market value for purposes of these Terms shall be made consistent with the resolutions adopted by the EIX Board of Directors on July 19, 2001 entitled "Fair Market Value Measure for Equity-Based Awards." EIX Options and Performance Shares are intended to qualify as performance-based compensation exempt from the deductibility limitations of Section 162(m) of the Code and these Terms shall be construed and interpreted consistent with that intent.

14.5: Transfer Representations. The Holder agrees that any securities acquired by him or her hereunder are being acquired for his or her own account for investment and not with a view to or for sale in connection with any distribution thereof and that he or she understands that such securities may not be sold, transferred, pledged, hypothecated, alienated, or otherwise assigned or disposed of without either registration under the Securities Act of 1933 or compliance with the exemption provided by Rule 144 or another applicable exemption under such act.
14.6: Award Not Funded. The Holder will have no right or claim to any specific funds, property or assets of the Companies as to any award of LTI.
14.7: Section 409A. Notwithstanding any provision of these Terms to the contrary, if the Holder is a "specified employee" as defined in Section 409A of the Code, the Holder shall not be entitled to any payment with respect to any LTI subject to Section 409A in connection with the Holder's Separation from Service until the earlier of (a) the date which is six (6) months after the Holder's Separation From Service for any reason other than the Holder's death, or (b) the date of the Holder's death. Any amounts otherwise payable to the Holder following the Holder's Separation From Service that are not so paid by reason of this Section 14.7 shall be paid as soon as practicable for EIX (and in all events within ninety (90) days) after the date that is six (6) months after the Holder's Separation From Service (or, if earlier, the date of the Holder's death). The provisions of this Section 14.7 shall only apply if, and to the extent, required to comply with Section 409A of the Code.
14.8: Claw-Back. Notwithstanding any provision of these Terms to the contrary, the LTI, as well as any shares of Common Stock, cash or other property that may be issued, delivered or paid in respect of the LTI, as well as any consideration that may be received in respect of a sale or other disposition of any such shares or property, shall be subject to any recoupment, "clawback" or similar provisions of applicable law, as well as any recoupment, "clawback" or similar policies of the Company that may be in effect from time to time.

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Exhibit 10.2

EDISON INTERNATIONAL 2011 Long-Term Incentives Terms and Conditions

Exhibit 31.1

CERTIFICATION

I, THEODORE F. CRAVER, JR., certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, of Edison International;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: May 2, 2011


		/s/ THEODORE F. CRAVER, JR. THEODORE F. CRAVER, JR. Chief Executive Officer

Exhibit 31.2

CERTIFICATION

I, W. JAMES SCILACCI, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, of Edison International;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: May 2, 2011


		/s/ W. JAMES SCILACCI W. JAMES SCILACCI Chief Financial Officer

Exhibit 32

STATEMENT PURSUANT TO 18 U.S.C. SECTION 1350, AS
ENACTED BY SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (the "Quarterly Report"), of Edison International (the "Company"), and pursuant to 18 U.S.C. Section 1350, as enacted by Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned certifies, to the best of his knowledge, that:

1.: The Quarterly Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and
2.: The information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 2, 2011


				/s/ THEODORE F. CRAVER, JR. THEODORE F. CRAVER, JR. Chief Executive Officer Edison International
				/s/ W. JAMES SCILACCI W. JAMES SCILACCI Chief Financial Officer Edison International

This statement accompanies the Quarterly Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.