10-Q

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TABLE OF CONTENTS

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

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 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 August 1, 2011
Common Stock, no par value	325,811,206

TABLE OF CONTENTS

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		10
	Note 4. Fair Value Measurements		12
	Note 5. Debt and Credit Agreements		17
	Note 6. Derivative Instruments and Hedging Activities		18
	Note 7. Income Taxes		25
	Note 8. Compensation and Benefit Plans		26
	Note 9. Commitments and Contingencies		29
	Note 10. Regulatory and Environmental Developments		35
	Note 11. Accumulated Other Comprehensive Loss		37
	Note 12. Supplemental Cash Flows Information		38
	Note 13. Preferred and Preference Stock of Utility		38
	Note 14. Regulatory Assets and Liabilities		39
	Note 15. Other Investments		39
	Note 16. Other Income and Expenses		40
	Note 17. Business Segments		41
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			42
FORWARD-LOOKING STATEMENTS			42
EDISON INTERNATIONAL MANAGEMENT OVERVIEW
	Highlights of Operating Results		44
	Management Overview of SCE		45
		Capital Program	45
		2012 CPUC General Rate Case	45
		FERC Formula Rates	46
		Nuclear Industry and Regulatory Response to Events in Japan	46
	Management Overview of EMG		46

i

	Cross-State Air Pollution Rule			46
	Homer City Capital Needs			47
	Midwest Generation Environmental Compliance Plans and Costs			48
		Walnut Creek Project		48
	Environmental Regulation Developments			48
SOUTHERN CALIFORNIA EDISON COMPANY
RESULTS OF OPERATIONS				49
	Three Months Ended June 30, 2011 versus June 30, 2010			49
		Utility Earning Activities		50
		Utility Cost-Recovery Activities		50
	Six Months Ended June 30, 2011 versus June 30, 2010			51
		Utility Earning Activities		51
		Utility Cost-Recovery Activities		52
	Supplemental Operating Revenue Information			52
	Income Taxes			53
LIQUIDITY AND CAPITAL RESOURCES				53
	Available Liquidity			53
		Debt Covenant		54
	Dividend Restrictions			54
	Margin and Collateral Deposits			54
		Workers Compensation Self-Insurance Fund		54
	Historical Consolidated Cash Flows			55
		Condensed Consolidated Statement of Cash Flows		55
			Net Cash Provided by Operating Activities	55
			Net Cash Provided by Financing Activities	55
			Net Cash Used by Investing Activities	56
	Contractual Obligations and Contingencies			56
		Contractual Obligations		56
		Contingencies		56
			Environmental Remediation	56
MARKET RISK EXPOSURES				56
	Commodity Price Risk			56
	Credit Risk			56
EDISON MISSION GROUP
RESULTS OF OPERATIONS				58
	Results of Continuing Operations			58
		Adjusted Operating Income ("AOI")—Overview		59
		Adjusted Operating Income from Consolidated Operations		61
			Midwest Generation Plants	61
			Homer City	62

ii

			Seasonality—Coal Plants	63
			Renewable Energy Projects	63
			Energy Trading	63
		Adjusted Operating Income from Unconsolidated Affiliates		64
		Interest Expense		64
		Income Taxes		65
LIQUIDITY AND CAPITAL RESOURCES				65
	Available Liquidity			65
		Homer City Outage		66
	Capital Investment Plan			67
		Environmental Capital Expenditures		67
		Plant Capital Expenditures		67
		Funding of Capital Expenditures		68
		Renewable Energy Projects		68
	Historical Segment Cash Flows			68
		Condensed Statement of Cash Flows		68
			Net Cash Provided by Operating Activities	68
			Net Cash Provided by Financing Activities	68
			Net Cash Provided by Investing Activities	69
	Credit Ratings			69
		Overview		69
		Credit Rating of EMMT		69
	Margin, Collateral Deposits and Other Credit Support for Energy Contracts			69
	Debt Covenants and Dividend Restrictions			70
		Credit Facility Financial Ratios		70
		Key Ratios of EMG's Principal Subsidiaries Affecting Dividends		70
		EME's Senior Notes and Guaranty of Powerton-Joliet Leases		70
	Contractual Obligations and Contingencies			71
		Fuel Supply Contracts		71
		Capital Expenditures		71
		Midwest Generation New Source Review and Other Litigation		71
		Homer City New Source Review and Other Litigation		71
	Off-Balance Sheet Transactions			71
MARKET RISK EXPOSURES				71
	Derivative Instruments			71
		Unrealized Gains and Losses		71
		Fair Value Disclosures		71
	Commodity Price Risk			72
		Energy Price Risk		72
		Capacity Price Risk		73
		Basis Risk		74

iii

		Coal and Transportation Price Risk		74
		Emission Allowances Price Risk		74
	Credit Risk			75
	Interest Rate Risk			76
EDISON INTERNATIONAL PARENT AND OTHER
RESULTS OF OPERATIONS				77
LIQUIDITY AND CAPITAL RESOURCES				77
	Historical Cash Flows			77
		Condensed Statement of Cash Flows		77
			Net Cash Used by Operating Activities	78
			Net Cash Provided (Used) by Financing Activities	78
EDISON INTERNATIONAL (CONSOLIDATED)
LIQUIDITY AND CAPITAL RESOURCES				79
	Contractual Obligations			79
CRITICAL ACCOUNTING ESTIMATES AND POLICIES				79
NEW ACCOUNTING GUIDANCE				79
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				79
ITEM 4. CONTROLS AND PROCEDURES				79
	Disclosure Controls and Procedures			79
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS				79
	California Coastal Commission Potential Environmental Proceeding			79
	Navajo Nation Litigation			80
	Midwest Generation New Source Review and Other Litigation			80
	Homer City New Source Review and Other Litigation			80
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS				80
	Purchases of Equity Securities by the Issuer and Affiliated Purchasers			80
ITEM 6. EXHIBITS				81
SIGNATURE				82

iv

GLOSSARY

The following terms and abbreviations appearing in the text of this report 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
CDWR	California Department of Water Resources
CEC	California Energy Commission
coal plants	Midwest Generation coal plants and Homer City plant
Commonwealth Edison	Commonwealth Edison Company
CPS	Combined Pollutant Standard
CPUC	California Public Utilities Commission
CSAPR	Cross-State Air Pollution Rule
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
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

v

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
NOx	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)
SO2	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

vi

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Statements of Income	Edison International
	Three months ended June 30,						Six months ended June 30,
(in millions, except per-share amounts, unaudited)	2011			2010			2011			2010
Electric utility	$	2,445		$	2,246		$	4,676		$	4,405
Competitive power generation		538			495			1,090			1,147
Total operating revenue		2,983			2,741			5,766			5,552
Fuel		256			254			515			549
Purchased power		649			612			1,158			1,220
Operations and maintenance		1,263			1,144			2,412			2,183
Depreciation, decommissioning and amortization		435			380			852			749
Total operating expenses		2,603			2,390			4,937			4,701
Operating income		380			351			829			851
Interest and dividend income		30			4			34			23
Equity in income from unconsolidated affiliates – net		18			20			12			39
Other income		42			36			83			70
Interest expense		(203	)		(175	)		(398	)		(343	)
Other expenses		(13	)		(16	)		(25	)		(28	)
Income from continuing operations before income taxes		254			220			535			612
Income tax expense (benefit)		62			(136	)		127			14
Income from continuing operations		192			356			408			598
Income (loss) from discontinued operations – net of tax		(1	)		1			(3	)		8
Net income		191			357			405			606
Dividends on preferred and preference stock of utility		15			13			29			26
Net income attributable to Edison International common shareholders	$	176		$	344		$	376		$	580
Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	$	177		$	343		$	379		$	572
Income (loss) from discontinued operations, net of tax		(1	)		1			(3	)		8
Net income attributable to Edison International common shareholders	$	176		$	344		$	376		$	580
Basic earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding		326			326			326			326
Continuing operations	$	0.54		$	1.05		$	1.16		$	1.75
Discontinued operations		—			—			(0.01	)		0.02
Total	$	0.54		$	1.05		$	1.15		$	1.77
Diluted earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities		329			327			328			327
Continuing operations	$	0.54		$	1.05		$	1.16		$	1.75
Discontinued operations		—			—			(0.01	)		0.02
Total	$	0.54		$	1.05		$	1.15		$	1.77
Dividends declared per common share	$	0.320		$	0.315		$	0.640		$	0.630

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

1

Consolidated Statements of Comprehensive Income						Edison International
			Three months ended June 30,						Six months ended June 30,
(in millions, unaudited)			2011			2010			2011			2010
Net income			$	191		$	357		$	405		$	606
Other comprehensive loss, net of tax:
	Pension and postretirement benefits other than pensions:
		Net gain arising during the period, net of income tax expense of $2 for the six months ended June 30, 2010		—			—			—			12
		Amortization of net (gain) loss included in net income, net of income tax expense (benefit) of $1 and $1 for the three months and $3 and $(4) for the six months ended June 30, 2011 and 2010, respectively		1			2			4			(6	)
		Prior service credit arising during the period, net of income tax expense of $1 for the six months ended June 30, 2010		—			—			—			2
		Amortization of prior service credit, net of income tax benefit of $1 for the six months ended June 30, 2010		—			—			—			(2	)
	Unrealized gain (loss) on derivatives qualified as cash flow hedges:
		Unrealized holding gain (loss) arising during the period, net of income tax expense (benefit) of $(9) and $(50) for the three months and $(5) and $12 for the six months ended June 30, 2011 and 2010, respectively		(14	)		(77	)		(8	)		18
		Reclassification adjustments included in net income, net of income tax benefit of $6 and $35 for the three months and $12 and $49 for the six months ended June 30, 2011 and 2010, respectively		(7	)		(53	)		(17	)		(73	)
Other comprehensive loss				(20	)		(128	)		(21	)		(49	)
Comprehensive income				171			229			384			557
Less: Comprehensive income attributable to noncontrolling interests				15			13			29			26
Comprehensive income attributable to Edison International			$	156		$	216		$	355		$	531

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

2

Consolidated Balance Sheets	Edison International
(in millions, unaudited)	June 30, 2011		December 31, 2010
ASSETS
Cash and cash equivalents	$	945	$	1,389
Receivables, less allowances of $87 and $85 for uncollectible accounts at respective dates		1,018		931
Accrued unbilled revenue		619		442
Inventory		589		568
Prepaid taxes		356		390
Derivative assets		117		133
Restricted cash		11		2
Margin and collateral deposits		65		65
Regulatory assets		469		378
Other current assets		148		124
Total current assets		4,337		4,422
Nuclear decommissioning trusts		3,657		3,480
Investments in unconsolidated affiliates		552		559
Other investments		231		223
Total investments		4,440		4,262
Utility property, plant and equipment, less accumulated depreciation of $6,486 and $6,319 at respective dates		25,847		24,778
Competitive power generation and other property, plant and equipment, less accumulated depreciation of $2,009 and $1,865 at respective dates		5,613		5,406
Total property, plant and equipment		31,460		30,184
Derivative assets		242		437
Restricted deposits		27		47
Rent payments in excess of levelized rent expense under plant operating leases		1,288		1,187
Regulatory assets		4,690		4,347
Other long-term assets		591		644
Total long-term assets		6,838		6,662
Total assets	$	47,075	$	45,530

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

3

Edison International
Consolidated Balance Sheets
(in millions, except share amounts, unaudited)	June 30, 2011			December 31, 2010
LIABILITIES AND EQUITY
Short-term debt	$	388		$	115
Current portion of long-term debt		53			48
Accounts payable		1,110			1,362
Accrued taxes		33			52
Accrued interest		225			205
Customer deposits		208			217
Derivative liabilities		238			217
Regulatory liabilities		820			738
Other current liabilities		807			998
Total current liabilities		3,882			3,952
Long-term debt		12,956			12,371
Deferred income taxes		5,819			5,625
Deferred investment tax credits		132			122
Customer advances		121			112
Derivative liabilities		580			468
Pensions and benefits		2,306			2,260
Asset retirement obligations		2,616			2,561
Regulatory liabilities		4,759			4,524
Other deferred credits and other long-term liabilities		2,147			2,041
Total deferred credits and other liabilities		18,480			17,713
Total liabilities		35,318			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)		2,347			2,331
Accumulated other comprehensive loss		(97	)		(76	)
Retained earnings		8,476			8,328
Total Edison International's common shareholders' equity		10,726			10,583
Preferred and preference stock of utility		1,029			907
Other noncontrolling interests		2			4
Total noncontrolling interests		1,031			911
Total equity		11,757			11,494
Total liabilities and equity	$	47,075		$	45,530

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

4

Consolidated Statements of Cash Flows		Edison International
		Six months ended June 30,
(in millions, unaudited)		2011			2010
Cash flows from operating activities:
Net income		$	405		$	606
Less: Income (loss) from discontinued operations			(3	)		8
Income from continuing operations			408			598
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization			852			749
Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)			75			74
Other amortization			75			56
Stock-based compensation			15			14
Equity in income from unconsolidated affiliates – net			(12	)		(39	)
Distributions from unconsolidated entities			15			39
Deferred income taxes and investment tax credits			223			247
Proceeds from U.S. treasury grants			—			92
Income from leveraged leases			(3	)		(2	)
Changes in operating assets and liabilities:
	Receivables		64			13
	Inventory		(21	)		(36	)
	Margin and collateral deposits – net of collateral received		1			12
	Prepaid taxes		34			(167	)
	Other current assets		(189	)		(136	)
	Rent payments in excess of levelized rent expense		(101	)		(111	)
	Accounts payable		66			(114	)
	Accrued taxes		(19	)		(69	)
	Other current liabilities		(212	)		(164	)
	Derivative assets and liabilities – net		303			806
	Regulatory assets and liabilities – net		(260	)		(720	)
	Other assets		(31	)		(36	)
	Other liabilities		(58	)		(152	)
Operating cash flows from discontinued operations			(3	)		8
Net cash provided by operating activities			1,222			962
Cash flows from financing activities:
Long-term debt issued			592			645
Long-term debt issuance costs			(5	)		(19	)
Long-term debt repaid			(30	)		(366	)
Bonds purchased			(56	)		—
Preference stock issued – net			123			—
Short-term debt financing – net			292			410
Settlements of stock-based compensation – net			(13	)		(2	)
Dividends and distributions to noncontrolling interests			(28	)		(25	)
Dividends paid			(209	)		(205	)
Net cash provided by financing activities		$	666		$	438

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

5

Edison International
Consolidated Statements of Cash Flows
	Six months ended June 30,
(in millions, unaudited)	2011			2010
Cash flows from investing activities:
Capital expenditures	$	(2,256	)	$	(2,070	)
Purchase of interest in acquired companies		—			(4	)
Proceeds from sale of nuclear decommissioning trust investments		1,146			600
Purchases of nuclear decommissioning trust investments and other		(1,230	)		(697	)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment		5			44
Investments in other assets		3			13
Effect of consolidation and deconsolidation of variable interest entities		—			(91	)
Net cash used by investing activities		(2,332	)		(2,205	)
Net decrease in cash and cash equivalents		(444	)		(805	)
Cash and cash equivalents, beginning of period		1,389			1,673
Cash and cash equivalents, end of period	$	945		$	868

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

6

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 ("GAAP") for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and six-month periods ended June 30, 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 GAAP.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $743 million and $1.1 billion at June 30, 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 $185 million and $197 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at June 30, 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)	June 30, 2011		December 31, 2010
Coal, gas, fuel oil and other raw materials	$	203	$	184
Spare parts, materials and supplies		386		384
Total inventory	$	589	$	568

Earnings Per Share

Edison International computes earnings per share ("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

7

International's 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 June 30,					Six months ended June 30,
(in millions)	2011		2010			2011		2010
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	177	$	343		$	379	$	572
Participating securities dividends		—		(2	)		—		(2	)
Income from continuing operations available to common shareholders	$	177	$	341		$	379	$	570
Weighted average common shares outstanding		326		326			326		326
Basic earnings per share – continuing operations	$	0.54	$	1.05		$	1.16	$	1.75
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	177	$	341		$	379	$	570
Income impact of assumed conversions		1		1			1		1
Income from continuing operations available to common shareholders and assumed conversions	$	178	$	342		$	380	$	571
Weighted average common shares outstanding		326		326			326		326
Incremental shares from assumed conversions		3		1			2		1
Adjusted weighted average shares – diluted		329		327			328		327
Diluted earnings per share – continuing operations	$	0.54	$	1.05		$	1.16	$	1.75

Stock-based compensation awards to purchase 5,896,940 and 9,645,334 shares of common stock for the three months ended June 30, 2011 and 2010, respectively, and 5,896,940 and 6,080,199 shares of common stock for the six months ended June 30, 2011 and 2010 respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares during the respective periods 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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Accounting Guidance Not Yet Adopted

Fair Value Measurement

In May 2011, the FASB issued an accounting standards update modifying the fair value measurement and disclosure guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the value be based on the individual security. This amendment also results in new disclosures primarily related to Level 3 measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. Edison International will adopt this guidance effective January 1, 2012 and does not expect the adoption of this standard will have a material impact on Edison International's consolidated statements of income, financial position or cash flows.

Presentation of Comprehensive Income

In June 2011, the FASB issued an accounting standards update on the presentation of comprehensive income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. Edison International will adopt this guidance effective January 1, 2012. Edison International currently presents the statement of comprehensive income immediately following the statement of income and expects to continue to do so. The adoption of this accounting standards update does not change the items that constitute net income and other comprehensive income.

Note 2. Consolidated Statements of Changes in Equity

The following table provides the changes in equity for the six months ended June 30, 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		—		—			376			376			—			29			405
Other comprehensive loss		—		(21	)		—			(21	)		—			—			(21	)
Common stock dividends declared ($0.64 per share)		—		—			(209	)		(209	)		—			—			(209	)
Dividends, distributions to noncontrolling interests and other		—		—			—			—			(2	)		(29	)		(31	)
Stock-based compensation and other		4		—			(17	)		(13	)		—			—			(13	)
Noncash stock-based compensation and other		12		—			(2	)		10			—			(1	)		9
Issuance of preference stock		—		—			—			—			—			123			123
Balance at June 30, 2011	$	2,347	$	(97	)	$	8,476		$	10,726		$	2		$	1,029		$	11,757

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

	Equity Attributable to Edison International											Noncontrolling Interests
(in millions)	Common Stock		Accumulated Other Comprehensive Income			Retained Earnings			Subtotal			Other			Preferred and Preference Stock			Total Equity
Balance at December 31, 2009	$	2,304	$	37		$	7,500		$	9,841		$	258		$	907		$	11,006
Net income		—		—			580			580			—			26			606
Other comprehensive loss		—		(49	)		—			(49	)		—			—			(49	)
Deconsolidation of variable interest entities		—		—			—			—			(249	)		—			(249	)
Cumulative effect of a change in accounting principle, net of tax		—		—			15			15			—			—			15
Common stock dividends declared ($0.63 per share)		—		—			(205	)		(205	)		—			—			(205	)
Dividends, distributions to noncontrolling interests and other		—		—			—			—			(3	)		(26	)		(29	)
Stock-based compensation and other		2		—			(4	)		(2	)		—			—			(2	)
Noncash stock-based compensation and other		9		—			(7	)		2			—			—			2
Balance at June 30, 2010	$	2,315	$	(12	)	$	7,879		$	10,182		$	6		$	907		$	11,095

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. 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 June 30, 2011 and December 31, 2010, EMG consolidated 13 and 14 projects, respectively, with a total generating capacity of 570 MW and 580 MW, respectively, that have interests held by others. In April 2011, EMG sold its 75% ownership interest in a Minnesota wind project.

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

(in millions)		June 30, 2011		December 31, 2010
Current assets		$	39	$	26
Net property, plant and equipment			712		739
Other long-term assets			5		6
	Total assets	$	756	$	771
Current liabilities		$	23	$	25
Long-term debt net of current portion			68		71
Deferred revenues			69		71
Other long-term liabilities			21		21
	Total liabilities	$	181	$	188
Noncontrolling interests		$	3	$	4

At June 30, 2011 and December 31, 2010, assets serving as collateral for the debt obligations had a carrying value of $163 million 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 have variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to operate the plants and 10 contracts with qualifying facilities ("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. 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. As a result, 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 June 30, 2011 and the amounts that SCE paid to these projects were $83 million and $117 million for the three months ended June 30, 2011 and 2010, respectively, and $169 million and $242 million for the six months ended June 30, 2011 and 2010, respectively. These amounts are recovered in customer rates.

Equity Interests

EMG accounts for domestic gas and wind energy projects in which it has less than a 100% ownership interest, and cannot exercise unilateral control, under the equity method. At June 30, 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 the Sunrise project and EMG's partner provides the fuel management services for the Big 4 projects. 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 accounts for its variable interests under the equity method.

At June 30, 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. In addition, EMG

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accounts for its interests in Community Wind North, which achieved commercial operation on May 28, 2011, under the equity method. The commercial and operating activities of these entities are jointly directed by representatives of each partner. Thus, EMG is not the primary beneficiary of these projects.

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

	June 30, 2011
(in millions)	Investment		Maximum Exposure
Natural gas-fired projects	$	321	$	321
Renewable energy projects		229		229

EMG's maximum exposure to loss in its VIEs accounted for under the equity method is generally limited to its investment in these entities. One of EMG's domestic energy projects has long-term debt that is secured by a pledge of project entity assets, but does not provide for recourse to EMG. Accordingly, a default under the project financing could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EMG's investment, but would not require EMG to contribute additional capital. At June 30, 2011, entities which EMG has accounted for under the equity method had indebtedness of $65 million, of which $16 million is proportionate to EMG's ownership interest in this project.

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 June 30, 2011
(in millions)		Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2		$	743	$	—	$	—		$	—		$	743
Derivative contracts:
	Electricity		—		44		231			(33	)		242
	Natural gas		—		65		11			—			76
	Fuel oil		6		—		—			(6	)		—
	Tolling		—		—		41			—			41
	Coal		—		1		—			(1	)		—
Subtotal of commodity contracts			6		110		283			(40	)		359
Long-term disability plan			9		—		—			—			9
Nuclear decommissioning trusts:
	Stocks3		2,062		—		—			—			2,062
	Municipal bonds		—		812		—			—			812
	U.S. government and agency securities		309		118		—			—			427
	Corporate bonds4		—		310		—			—			310
	Short-term investments, primarily cash equivalents5		4		31		—			—			35
Subtotal of nuclear decommissioning trusts			2,375		1,271		—			—			3,646
Total assets6			3,133		1,381		283			(40	)		4,757
Liabilities at Fair Value
Derivative contracts:
	Electricity		—		9		71			(9	)		71
	Natural gas		—		239		6			(1	)		244
	Tolling		—		—		481			—			481
Subtotal of commodity contracts			—		248		558			(10	)		796
Interest rate contracts			—		22		—			—			22
Total liabilities			—		270		558			(10	)		818
Net assets (liabilities)		$	3,133	$	1,111	$	(275	)	$	(30	)	$	3,939

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		As of December 31, 2010
(in millions)		Level 1		Level 2		Level 3		Netting and Collateral1			Total
Assets at Fair Value
Money market funds2		$	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:
	Stocks3		2,029		—		—		—			2,029
	Municipal bonds		—		790		—		—			790
	Corporate bonds4		—		346		—		—			346
	U.S. government and agency securities		215		73		—		—			288
	Short-term investments, primarily cash equivalents5		1		31		—		—			32
Subtotal of nuclear decommissioning trusts			2,245		1,240		—		—			3,485
Total assets6			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 June 30, 2011 and December 31, 2010, respectively.

⁴

Corporate bonds are diversified, and included $27 million at both June 30, 2011 and December 31, 2010, respectively, for collateralized mortgage obligations and other asset backed securities.

⁵

Excludes net receivables of $11 million and net liabilities of $5 million at June 30, 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 June 30, 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 June 30,						Six months ended June 30,
(in millions)		2011			2010			2011			2010
Fair value, net asset (liabilities) at beginning of period		$	(44	)	$	(397	)	$	97		$	62
Total realized/unrealized gains (losses):
	Included in earnings1		18			(18	)		18			27
	Included in regulatory assets and liabilities2		(247	)		(294	)		(382	)		(781	)
	Included in accumulated other comprehensive income		(4	)		(2	)		(3	)		4
Purchases			22			26			28			32
Settlements			(20	)		(24	)		(31	)		(52	)
Transfers in or out of Level 3			—			6			(2	)		5
Fair value, net liability at end of period		$	(275	)	$	(703	)	$	(275	)	$	(703	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period3		$	(226	)	$	(287	)	$	(368	)	$	(717	)

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 $14 million and $(2) million for the three months ended June 30, 2011 and 2010, respectively, and were $8 million and $32 million for the six months ended June 30, 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 financial 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), 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 June 30, 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:

	June 30, 2011				December 31, 2010
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	13,009	$	13,075	$	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

Long-Term Debt

In May 2011, SCE issued $500 million of 3.875% first and refunding mortgage bonds due in 2021. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.

In May 2011, SCE purchased $56 million of its tax-exempt bonds that were subject to remarketing and also converted these bonds to a variable rate structure. These bonds are held by SCE and remain outstanding and have not been retired or cancelled.

Project Financings

Walnut Creek

On July 27, 2011, EMG completed, through wholly owned subsidiaries, non-recourse financings to fund construction of the Walnut Creek project, a 479 MW natural gas-fired peaker plant in southern California. The financings included $122 million of letter of credit and working capital facilities, and also included floating rate construction loans totaling $495 million (with initial fundings of $48 million) that will convert to 10-year amortizing term loans by June 30, 2013, subject to meeting specified conditions.

As of July 27, 2011, EME entered into interest rate swap agreements and forward-starting interest rate swap agreements that converted the floating rate London Interbank Offered Rate ("LIBOR") construction loans to fixed rates. Under the interest rate swap agreements, EME will pay fixed rates of an average of 0.81% through May 31, 2013. Under the forward-starting swaps agreements, EME will pay an average fixed rate of 3.59% beginning June 30, 2013 through May 31, 2023. Interest under the project-level construction term loan of $442 million initially accrues at LIBOR plus 2.25% and increases by 0.25% after the third, sixth and ninth anniversaries. Interest on the intermediate holding company construction term loan of $53 million accrues at LIBOR plus 4.00% over the term.

Viento Funding II Wind Financing Amendment

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 June 30, 2011, $216 million was outstanding under this loan. The amount of outstanding letters of credit was $23 million. Interest under the term loan accrues at LIBOR plus 2.75% initially with the rate increasing 0.25% on every fourth anniversary.

Credit Agreements and Short-Term Debt

At June 30, 2011, SCE's outstanding short-term debt was $200 million at a weighted-average interest rate of 0.33%. 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 June 30, 2011, letters of credit issued under SCE's credit facilities aggregated $71 million and are scheduled to expire in twelve months or less.

At June 30, 2011, Edison International (Parent)'s outstanding short-term debt was $79 million at a weighted-average interest rate of 0.55%. At December 31, 2010, the outstanding short-term debt was $19 million at a weighted-average interest rate of 0.63%.

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Letters of Credit

At June 30, 2011, standby letters of credit under EME's credit facility aggregated $116 million and were scheduled to expire as follows: $39 million in 2011 and $77 million in 2012. The aggregate amount includes $39 million of letters of credit issued for the benefit of SCE, which is the power purchase agreement counterparty for the Walnut Creek project. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $51 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 $18 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 options, swaps, forwards, tolling arrangements and CRRs. These transactions are pre-approved by the California Public Utilities Commission ("CPUC") or executed in compliance with CPUC-approved procurement plans. SCE recovers its related hedging costs through the energy resource recovery account ("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 and sold to the California and other wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities, power purchase agreements and California Department of Water Resources ("CDWR") contracts allocated to SCE.

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	June 30, 2011		December 31, 2010
Electricity options, swaps and forwards	GWh		34,471		32,138
Natural gas options, swaps and forwards	Bcf		255		250
CRRs	GWh		147,992		181,291
Tolling arrangements	GWh		105,631		114,599

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Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at June 30, 2011:

	Derivative Assets									Derivative Liabilities
(in millions)	Short- Term			Long- Term			Subtotal			Short- Term			Long- Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	89		$	200		$	289		$	243		$	579		$	822		$	533
Netting and collateral		(11	)		(21	)		(32	)		(12	)		(21	)		(33	)		(1	)
Total	$	78		$	179		$	257		$	231		$	558		$	789		$	532

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.

The following table summarizes the components of economic hedging activity:

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Realized losses	$	(35	)	$	(38	)	$	(74	)	$	(62	)
Unrealized losses		(227	)		(276	)		(323	)		(857	)

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 $164 million and $67 million as of June 30, 2011 and December 31, 2010, respectively, for which SCE has posted no collateral and $4 million of collateral to its

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counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2011, SCE would be required to post $12 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. 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 its 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 EMG's consolidated balance sheets with offsetting changes recorded on the consolidated statements of operations. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized, to the extent effective, on EMG's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive loss until the related forecasted 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 operations.

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 its consolidated balance sheets.

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Notional Volumes of Derivative Instruments

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

June 30, 2011
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges			Economic Hedges			Trading Activities
Electricity	Forwards/Futures	Sales	GWh		18,901	1		17,660	3		39,629
Electricity	Forwards/Futures	Purchases	GWh		203	1		17,750	3		42,863
Electricity	Capacity	Sales	MW-Day (in thousands)		171	2		—			17	2
Electricity	Capacity	Purchases	MW-Day (in thousands)		17	2		—			247	2
Electricity	Congestion	Sales	GWh		—			124	4		14,314	4
Electricity	Congestion	Purchases	GWh		—			5,459	4		287,221	4
Natural gas	Forwards/Futures	Sales	bcf		—			1.5			354.1
Natural gas	Forwards/Futures	Purchases	bcf		—			1.5			351.8
Fuel oil	Forwards/Futures	Sales	barrels		—			—			45,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			240,000			70,000
Coal	Forwards/Futures	Sales	tons		—			—			2,564,250
Coal	Forwards/Futures	Purchases	tons		—			—			2,564,250

(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	$	84	June 2016
Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.415%) debt	Cash flow		110	December 2020
Amortizing interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt	Cash flow		120	December 2025
Amortizing interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt	Cash flow		67	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.

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Fair Value of Derivative Instruments

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

June 30, 2011
		Derivative Assets									Derivative Liabilities
																				Net Assets (Liabilities)
(in millions)		Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal
Non-trading activities
	Cash flow hedges	$	27		$	2		$	29		$	14		$	34		$	48		$	(19	)
	Economic hedges		60			4			64			51			1			52			12
Trading activities			141			88			229			98			20			118			111
			228			94			322			163			55			218			104
Netting and collateral received1			(189	)		(31	)		(220	)		(157	)		(32	)		(189	)		(31	)
Total		$	39		$	63		$	102		$	6		$	23		$	29		$	73

December 31, 2010
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 received1			(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 cash flow hedge activity as part of accumulated other comprehensive loss:

	Cash Flow Hedge Activity1 Six Months Ended June 30,
							Income Statement Location
(in millions)	2011			2010
Beginning of period derivative gains	$	27		$	175
Effective portion of changes in fair value		(13	)		30
Reclassification to net income		(29	)		(122	)	Competitive power generation revenue
End of period derivative gains (losses)	$	(15	)	$	83

¹

Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income (loss) at June 30, 2011 and 2010 were $(9) million and $50 million, respectively.

For additional information, see Note 11—Accumulated Other Comprehensive Loss.

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 (losses) of none and $(7) million during the second quarters of 2011 and 2010, respectively, and $2 million and $1 million during the six months ended June 30, 2011 and 2010, respectively, in operating revenues on the consolidated statements of operations representing the amount of cash flow hedge ineffectiveness.

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

		Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	Income Statement Location	2011			2010			2011		2010
Economic hedges	Competitive power generation revenue	$	20		$	(3	)	$	26	$	(7	)
	Fuel		(2	)		(2	)		4		(1	)
Trading activities	Competitive power generation revenue		41			33			57		80

Contingent Features

Certain derivative instruments contain margin and collateral deposit requirements. Since EMG's subsidiaries' credit ratings are below investment grade, EMG's subsidiaries have 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 June 30, 2011 and, accordingly, the contingent features described below do not currently have liquidity exposure. 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. Edison Mission Marketing & Trading, Inc. ("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's subsidiaries to termination payments or additional collateral postings.

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)		June 30, 2011		December 31, 2010
Collateral provided to counterparties:
	Offset against derivative liabilities	$	4	$	8
	Reflected in margin and collateral deposits		64		65
Collateral received from counterparties:
	Offset against derivative assets		33		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 June 30,						Six months ended June 30,
(in millions)			2011			2010			2011			2010
Income from continuing operations before income taxes			$	254		$	220		$	535		$	612
Provision for income tax at federal statutory rate of 35%				89			77			187			214
Increase (decrease) in income tax from:
	Items presented with related state income tax, net:
		Global Settlement related1		—			(138	)		—			(138	)
		Change in tax accounting method for asset removal costs2		—			(40	)		—			(40	)
	State tax – net of federal benefit			4			16			13			23
	Health care legislation3			—			—			—			39
	Production and housing credits			(19	)		(19	)		(36	)		(34	)
	Property-related and other			(12	)		(32	)		(37	)		(50	)
Total income tax expense from continuing operations			$	62		$	(136	)	$	127		$	14
Effective tax rate				24%			(62%	)		24%			2%

¹

During the second quarter of 2010, Edison International recognized a $138 million earnings benefit resulting from the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service ("IRS") in 2009 as part of the Global Settlement.

²

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

³

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 decreased benefit provided by property-related and other items was primarily due to lower deductions for internally developed software in 2011 compared to the respective periods in 2010.

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 upon examination. 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.

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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		26			35
Tax positions taken during a prior year:
	Increases		14			127
	Decreases		(10	)		(40	)
	Decreases for settlements during the period		—			(82	)
Balance at June 30,		$	595		$	704

As of June 30, 2011 and December 31, 2010, $468 million and $455 million, respectively, of the unrecognized tax benefits, if recognized, would impact the effective tax rate.

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 $189 million, including interest and penalties through June 30, 2011 (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 $91 million, including interest through June 30, 2011.

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 $222 million and $213 million as of June 30, 2011 and December 31, 2010, respectively.

The net after-tax interest and penalties recognized in income tax expense was $2 million and $5 million for the three- and six-month periods ended June 30, 2011, respectively, compared to a benefit of $101 million and $88 million for the same periods in 2010.

Note 8. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

During the six months ended June 30, 2011, Edison International made contributions of $61 million and during the remainder of 2011, expects to make $69 million of additional contributions. 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.

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Expense components are:

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Service cost	$	43		$	34		$	86		$	68
Interest cost		52			54			104			108
Expected return on plan assets		(60	)		(52	)		(120	)		(104	)
Amortization of prior service cost		2			2			4			4
Amortization of net loss		6			7			12			14
Expense under accounting standards		43			45			86			90
Regulatory adjustment – deferred		(6	)		(14	)		(12	)		(28	)
Total expense recognized	$	37		$	31		$	74		$	62

Postretirement Benefits Other Than Pensions

During the six months ended June 30, 2011, Edison International made contributions of $12 million and during the remainder of 2011, expects to make $44 million of additional contributions. Annual contributions made to SCE's 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 June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Service cost	$	11		$	8		$	22		$	16
Interest cost		33			31			66			62
Expected return on plan assets		(28	)		(25	)		(56	)		(50	)
Amortization of prior service cost (credit)		(9	)		(9	)		(18	)		(18	)
Amortization of net loss		9			8			18			16
Total expense	$	16		$	13		$	32		$	26

Stock-Based Compensation

During the six months ended June 30, 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		3,314,149			37.95
Expired		(87,641	)		47.93
Forfeited		(244,066	)		32.52
Exercised		(1,002,771	)		24.74
Outstanding at June 30, 2011		21,121,880			34.37		6.26
Vested and expected to vest at June 30, 2011		20,639,870			34.38		6.21	$	136
Exercisable at June 30, 2011		12,613,025			34.70		4.74		93

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At June 30, 2011, there was $28 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					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		148,697			27.96		148,697
Forfeited		(113,762	)		43.42		(113,762	)
Nonvested at June 30, 2011		449,963			28.04		449,963			29.43

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.

At June 30, 2011, there was $6 million 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:

	Restricted Stock Units			Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2010		644,796		$	32.18
Granted		247,408			37.95
Forfeited		(16,467	)		32.13
Paid Out		(104,420	)		52.35
Nonvested at June 30, 2011		771,317		$	31.98

At June 30, 2011, there was $12 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $4 million in 2011, $5 million in 2012 and $3 million in 2013.

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Supplemental Data on Stock Based Compensation

		Three months ended June 30,				Six months ended June 30,
(in millions)		2011		2010		2011		2010
Stock based compensation expense1		$	11	$	9	$	17	$	17
Income tax benefits related to stock compensation expense			5		4		7		7
Excess tax benefits2			2		1		4		2
Stock options
	Cash used to purchase shares to settle options		20		6		39		13
	Cash from participants to exercise stock options		12		4		25		9
	Value of options exercised		8		2		14		4
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 for both the six month periods ended June 30, 2011 and 2010.

Note 9. Commitments and Contingencies

Third-Party Power Purchase Agreements

At June 30, 2011, additional renewable energy power purchase contracts became effective and were classified as operating leases. SCE's additional commitments under these contracts are estimated to be: $6 million in 2011, $116 million each year in 2012 – 2015 and $1.9 billion for the period remaining thereafter.

Other Commitments

Fuel Supply Contracts

At June 30, 2011, Midwest Generation and EME Homer City Generation L.P. ("Homer City") had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses. These commitments are estimated to aggregate $634 million, summarized as follows: $277 million for the remainder of 2011, $304 million in 2012 and $53 million in 2013. In July 2011, Midwest Generation entered into additional contractual agreements for the purchase of coal. These commitments are estimated to be $6 million for the remainder of 2011, $28 million for 2012, $145 million for 2013 and $150 million for 2014.

Turbine Commitments

At June 30, 2011, EMG had commitments to purchase wind turbines of $45 million due in 2011 and $8 million due in 2012. Based on a June 2011 contract amendment, EMG's failure to schedule turbine delivery by September 2011 would result in a termination obligation equal to its turbine deposit, which would result in a $29 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.

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Capital Expenditures

At June 30, 2011, EMG's subsidiaries had firm commitments to spend approximately $242 million during the remainder of 2011, $205 million in 2012 and $19 million in 2013 on capital and construction expenditures. These expenditures primarily relate to the Walnut Creek project, selective non-catalytic reduction (SNCR) equipment at the Midwest Generation plants, and the construction of wind projects. EMG intends to fund these expenditures through project level financing, U.S. Treasury grants, Midwest Generation and EME lines of credit, if available, cash on hand and cash generated from operations.

Guarantees and Indemnities

Edison International's subsidiaries have various financial and performance guarantees and indemnity agreements which are issued in the normal course of business. The contracts discussed below included performance guarantees.

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 obligations are reduced by any insurance proceeds and tax benefits related to such indemnified claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. 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. These indemnities are not limited in term or amount. 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 and Other Litigation." 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 Midwest Generation's 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. 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 222 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at June 30, 2011. Midwest Generation had recorded a liability of $55 million at June 30, 2011 related to this contractual 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. 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. EME has not recorded a liability related to this indemnity. For discussion of the New Source Review lawsuit filed against Homer City, see "—Contingencies—Homer City New Source Review and Other Litigation."

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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. At June 30, 2011, EME had recorded a liability of $45 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). Not all indemnities under the asset sale agreements have specific expiration dates. Due to the nature of these potential obligations, a maximum potential liability cannot be determined and has not been recorded as a liability related to these indemnities.

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. EME has not recorded a liability for these matters.

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 indemnities for specified environmental liabilities and income taxes with respect to assets sold. Edison International's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances Edison International may have recourse against third parties. Edison International has not recorded a liability related to these indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.

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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 and Other Litigation

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 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") emission 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 emission 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.

Nine of ten PSD claims have been dismissed, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court has 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.

In May 2011, two complaints were filed against Midwest Generation in the Northern District of Illinois by residents living near the Crawford and Fisk facilities on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs seek to have their suits certified as a class action and request injunctive relief, as well as compensatory and punitive damages.

Adverse decisions in these cases could involve penalties and remedial actions that could have a material 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 and Other Litigation

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, 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 emission 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

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environment caused by the alleged CAA violations. The 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, as well as compensatory and punitive damages.

In April 2011, Homer City filed motions to dismiss both complaints. Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material 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

On August 1, 2011, SCE and the other defendants entered into a comprehensive settlement with the Navajo Nation of the litigation filed in June 1999 against SCE and others concerning royalty payments to the Navajo for the coal supplied to the Mohave Generating Station. As amended in April 2010, the Navajo Nation's complaint asserted claims for, among other things, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The settlement will result in a payment to the Navajo Nation and other related parties. As a result of the settlement, the Navajo Nation lawsuit will be dismissed. The settlement agreement reached with the Navajo Nation will not impact SCE's results of operations.

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 single 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 June 30, 2011, Edison International's recorded estimated minimum liability to remediate its 26 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 (2 sites primarily related to Midwest Generation) was $60 million, of which $54 million was related to SCE, including $18 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. 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 $192 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 $32 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). In addition, SCE expects to recover 100% of environmental remediation costs incurred at the majority of the remaining sites through customer rates, representing $21 million of its recorded liability. SCE has recorded a regulatory asset of $53 million at June 30, 2011 for its estimated minimum environmental cleanup costs expected to be recovered through customer rates.

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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 $5 million to $17 million. Costs incurred for the six months ended June 30, 2011 and 2010, were $7 million and $3 million, respectively.

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 estimates.

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 June 2010, the United States Court of Federal Claims issued a decision granting SCE and its co-owners damages of approximately $142 million to recover costs incurred through December 31, 2005 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. The decision 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.

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Note 10. Regulatory and Environmental Developments

Environmental Developments

Cross-State Air Pollution Rule

On July 6, 2011, the US EPA adopted its final Cross-State Air Pollution Rule ("CSAPR") which will replace the Clean Air Interstate Rule ("CAIR") beginning on January 1, 2012. CSAPR is the final form of a previously proposed replacement for the CAIR, called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual sulfur dioxide ("SO₂") emissions and annual ozone season nitrogen oxide ("NO_x") emissions in two phases: a first phase effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO₂ emissions.

CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO₂ or NO_x emissions from operations will need to be matched by a sufficient amount of SO₂ or NO_x allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO₂ and NO_x allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual compliance period, units must surrender allowances for each ton of SO₂ and NO_x emitted or face penalties. While trading of allowances is permitted within designated groups of states, the rule provides for enhanced penalties against a unit that surrenders allowances in excess of certain predefined limits for itself and for the state in which it is located.

The installation of SO₂ controls will require capital commitments for the Midwest Generation plants well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. EMG believes that Midwest Generation's current environmental remediation plan, including allocated allowances and capital expenditures, required to meet the CPS will also comply with the requirements of CSAPR. However, the SO₂ allowances allocated to Homer City in CSAPR Phase I (25,797 tons in 2012 and 2013) are significantly lower than the amount that would be required based on Homer City's historical emissions (2010 SO₂ emissions were 112,951 tons). Therefore, pending installation of additional equipment for Units 1 and 2 (Homer City's Unit 3 is equipped with a wet scrubber flue gas desulfurization system to meet environmental standards), Homer City expects that it will be required to procure additional allowances. It is unclear at this time whether SO₂ allowances in sufficient quantity and at prices that Homer City can pass through in power prices will be available in 2012 and 2013. Also, Homer City's SO₂ shortfall is expected to exceed limits on the number of allowances it will be permitted to surrender, and, therefore, may subject Homer City to penalties in certain cases. Accordingly, Homer City is evaluating alternative options, including reduced dispatch and fuel switching, for complying with Phase I of CSAPR. Failure by Homer City to develop and implement a Phase I compliance plan based on allowances could result in its modifying operations at one or more units or significantly curtailing power output. The cost of allowances, together with possible operational impacts or reductions of output, which may be required to comply with Phase I of CSAPR, could have a material effect on Homer City.

Homer City has begun work on designing SO₂ and particulate emissions control equipment for Units 1 and 2. While the Phase II SO₂ emission allowances under CSAPR (11,068 tons) are less than were contemplated under the proposed Clean Air Transport Rule, the additional reductions are not expected to materially change the design for the SO₂ controls at Units 1 and 2. The installation of those SO₂ controls will require capital commitments for the Homer City plant well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. Given the relatively short period of time before Phase II of CSAPR takes effect in 2014, there is no assurance that Homer City will be able to complete all the work that will be required before the deadline. Homer City is continuing to review technologies available to reduce SO₂ and mercury emissions; however, it has not determined the most effective and efficient technology to meet all requirements that may be imposed on it. Consequently, the timing, selection of technology and ultimate capital costs remain uncertain. Based on preliminary estimates, Homer City currently believes the cost of such equipment may be between $600 million and $700 million.

Homer City does not currently have sufficient capital and does not expect to generate sufficient capital from operations to fund such retrofits and will have to seek financing, which will be subject to decisions by Homer City's lessors, holders of the pass-through certificates and new providers of capital funding. There is

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no assurance that sufficient financing will be obtained or will not result in significant dilution of Homer City's interest in the Homer City plant.

Proposed Hazardous Air Pollutant Regulations

In March 2011, the US EPA issued proposed National Emission Standards for Hazardous Air Pollutants, limiting emissions of hazardous air pollutants from coal- and oil-fired electrical generating units. This regulation is expected to be finalized by November 2011. Based on its continuing review, EMG does not expect that these standards, if adopted as proposed, 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. EMG also does not expect that these standards, if adopted as proposed, would require Homer City to make additional capital requirements beyond those that would be required to comply with CSAPR.

Water Quality

Once-Through Cooling Issues

In March 2011, the US EPA issued proposed 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 evaluating the proposed standards and believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable for both the Midwest Generation plants and the Homer City plant without incurring material additional capital expenditures or operating costs. 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. If other coastal power plants in California that rely on once-through cooling are forced to shut down or limit operations, the California policy may also significantly impact SCE's ability to procure generating capacity from those plants, which could have an adverse effect on system reliability and the cost of electricity.

Greenhouse Gas Regulation

California Air Resources Board's ("CARB") regulations implementing a California cap-and-trade program continue to be the subject of litigation. In June 2011, the CARB announced that initial cap-and-trade program compliance for the electricity sector would be delayed until January 2013.

In April 2011, California enacted a law requiring that California utilities to procure 33% of their electricity requirements from renewable resources, as defined in the statute. The law requires implementation by the CPUC. The impact of the new 33% law will depend on how the CPUC implements the law, which remains uncertain.

Greenhouse Gas Litigation Developments

In June 2011, the U.S. Supreme Court dismissed public nuisance claims against five power companies, ruling that the CAA and the US EPA actions it authorizes displace federal common law nuisance claims that might arise from the emission of greenhouse gases. The court also affirmed the Second Circuit's determination that at least some of the plaintiffs had standing to bring the case. The court did not address whether the CAA also preempts state law claims arising from the same circumstances.

Parties to the Kivalina case, the appeal of which was deferred before the Ninth Circuit Court of Appeals pending the Supreme Court's ruling described above, have requested that the appeal recommence and have asked for permission to file additional briefs on the impact of the Supreme Court's ruling. The Kivalina case was brought by the Alaskan Native Village of Kivalina seeking damages of up to $400 million for the

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cost of relocating the village because the plaintiffs claim that the Arctic ice that has protected the village is melting as a result of climate change. The federal district court dismissed the case against Edison International and the other defendants in October 2009. Due to the nature of these potential obligations, Edison International is unable to estimate the potential liability, if any.

On May 27, 2011, private citizens filed a purported class action complaint in the United States District Court for the Southern District of Mississippi, naming among a large number of defendants, Edison International and its subsidiaries, including SCE and EME. Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of greenhouse gases that have contributed to climate change and sea level rise, which in turn are alleged to have increased the destructive force of Hurricane Katrina. The lawsuit alleges causes of action for negligence, public and private nuisance, and trespass, and seeks unspecified compensatory and punitive damages. The claims in this lawsuit are nearly identical to a subset of the claims that were raised against many of the same defendants in a previous lawsuit that was filed in, and dismissed by, the same federal district court where the current case has been filed.

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		(25	)		4			—			(21	)
Balance at June 30, 2011	$	(9	)	$	(83	)	$	(5	)	$	(97	)

Included in accumulated other comprehensive loss at June 30, 2011 was $4 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $13 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 $8 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy 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.

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Note 12. Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

			Six months ended June 30,
(in millions)			2011			2010
Cash payments (receipts) for interest and taxes:
	Interest – net of amounts capitalized		$	321		$	305
	Tax payments (refunds) – net			(44	)		179
Noncash investing and financing activities:
	Accrued capital expenditures		$	388		$	333
	Purchase of equipment with note payable		$	56		$	—
	Details of debt exchange:
		Pollution-control bonds redeemed	$	(56	)	$	(203	)
		Pollution-control bonds issued		56			203
	Consolidation of variable interest entities:
		Assets other than cash	$	—		$	(94	)
		Liabilities and non-controlling interests		—			99
	Deconsolidation of variable interest entities:
		Assets other than cash	$	—		$	380
		Liabilities and noncontrolling interests		—			(476	)
	Dividends declared but not paid:
		Common stock	$	104		$	103
		Preferred and preference stock		15			13

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 for a price of $100 per share plus accrued and unpaid dividends, if any. These shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used for general corporate purposes.

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Note 14. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)		June 30, 2011		December 31, 2010
Current:
	Regulatory balancing accounts	$	268	$	213
	Energy derivatives		194		162
	Other		7		3
			469		378
Long-term:
	Deferred income taxes – net		1,912		1,855
	Pensions and other postretirement benefits		1,089		1,097
	Unamortized generation investment – net		328		355
	Unamortized loss on reacquired debt		258		268
	Energy derivatives		465		177
	Nuclear-related ARO investment – net		163		154
	Unamortized distribution investment – net		125		105
	Regulatory balancing accounts		53		56
	Other		297		280
			4,690		4,347
Total Regulatory Assets		$	5,159	$	4,725

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	June 30, 2011		December 31, 2010
Current:
Regulatory balancing accounts	$	818	$	733
Other		2		5
		820		738
Long-term:
Costs of removal		2,663		2,623
ARO		1,250		1,099
Regulatory balancing accounts		846		802
		4,759		4,524
Total Regulatory Liabilities	$	5,579	$	5,262

Note 15. Other Investments

Nuclear Decommissioning Trusts

Future 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.

39

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

		Amortized Cost				Fair Value
(in millions)	Longest Maturity Dates	June 30, 2011		December 31, 2010		June 30, 2011		December 31, 2010
Stocks	—	$	862	$	895	$	2,062	$	2,029
Municipal bonds	2050		699		706		812		790
U.S. government and agency securities	2041		396		270		427		288
Corporate bonds	2054		255		288		310		346
Short-term investments and receivables/payables	One-year		44		26		46		27
Total		$	2,256	$	2,185	$	3,657	$	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 $524 million and $315 million for the three months ended June 30, 2011 and 2010, respectively, and $1.1 billion and $600 million for the six months ended June 30, 2011 and 2010, respectively. Unrealized holding gains, net of losses, were $1.4 billion and $1.3 billion at June 30, 2011 and December 31, 2010, respectively.

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

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Balance at beginning of period	$	3,619		$	3,248		$	3,480		$	3,140
Realized gains – net		12			13			35			34
Unrealized gains (losses) – net		4			(205	)		106			(143	)
Other-than-temporary impairments		(4	)		(7	)		(13	)		(11	)
Interest, dividends, contributions and other		26			34			49			63
Balance at end of period	$	3,657		$	3,083		$	3,657		$	3,083

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 June 30,				Six months ended June 30,
(in millions)		2011		2010		2011		2010
Other income:
	Equity AFUDC	$	27	$	25	$	56	$	54
	Increase in cash surrender value of life insurance policies		7		6		13		12
	Other		5		4		8		4
Total utility other income			39		35		77		70
Competitive power generation and other income			3		1		6		—
Total other income		$	42	$	36	$	83	$	70
Other expenses:
	Civic, political and related activities and donations	$	9	$	9	$	15	$	15
	Other		4		6		10		11
Total utility other expenses			13		15		25		26
Competitive power generation and other expenses			—		1		—		2
Total other expenses		$	13	$	16	$	25	$	28

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Note 17. Business Segments

Edison International has two business segments for financial reporting purposes: an electric utility operation segment (SCE) and a competitive power generation segment (EMG). The significant accounting policies of the segments are the same as those described in Note 1.

Reportable Segments Information

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

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Operating Revenue:
Electric utility	$	2,446		$	2,247		$	4,678		$	4,406
Competitive power generation		538			495			1,090			1,147
Parent and other2		(1	)		(1	)		(2	)		(1	)
Consolidated Edison International	$	2,983		$	2,741		$	5,766		$	5,552
Net Income (Loss) attributable to Edison International:
Electric utility	$	211		$	301		$	433		$	465
Competitive power generation1		(31	)		27			(51	)		104
Parent and other2		(4	)		16			(6	)		11
Consolidated Edison International	$	176		$	344		$	376		$	580

Segment balance sheet information was:

(in millions)		June 30, 2011			December 31, 2010
Total Assets:
	Electric utility	$	37,365		$	35,906
	Competitive power generation		9,804			9,597
	Parent and other2		(94	)		27
Consolidated Edison International		$	47,075		$	45,530

¹

Includes earnings (losses) from discontinued operations of $(1) million and $1 million for the three months ended June 30, 2011 and 2010, respectively, and $(3) million and $8 million for the six months ended June 30, 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, including compliance with CPS at Midwest Generation and the CSAPR and the proposed National Emission Standards for Hazardous Air Pollutants at Midwest Generation and Homer City;

•

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;

•

possible customer bypass or departure due to technological advancements or cumulative rate impacts that make self-generation or use of alternative energy sources economically viable;

•

risks associated with the operation of transmission and distribution assets and nuclear and other power generating facilities including: nuclear fuel storage issues, public safety 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;

42

•

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;

•

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- and six-month periods ended June 30, 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- and six-month periods ended June 30, 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.

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EDISON INTERNATIONAL MANAGEMENT OVERVIEW

Highlights of Operating Results

			Three months ended June 30,									Six months ended June 30,
(in millions)			2011			2010			Change			2011			2010			Change
Net Income (Loss) attributable to Edison International
	SCE		$	211		$	301		$	(90	)	$	433		$	465		$	(32	)
	EMG			(31	)		27			(58	)		(51	)		104			(155	)
	Edison International Parent and Other			(4	)		16			(20	)		(6	)		11			(17	)
	Edison International Consolidated			176			344			(168	)		376			580			(204	)
Non-Core Items
	Global Settlement:
		SCE		—			53			(53	)		—			53			(53	)
		EMG		—			58			(58	)		—			58			(58	)
		Edison International Parent and Other		—			27			(27	)		—			27			(27	)
	SCE – tax impact of health care legislation			—			—			—			—			(39	)		39
	EMG discontinued operations			(1	)		1			(2	)		(3	)		8			(11	)
	Total non-core items			(1	)		139			(140	)		(3	)		107			(110	)
Core Earnings (Losses)
	SCE			211			248			(37	)		433			451			(18	)
	EMG			(30	)		(32	)		2			(48	)		38			(86	)
	Edison International Parent and Other			(4	)		(11	)		7			(6	)		(16	)		10
	Edison International Consolidated		$	177		$	205		$	(28	)	$	379		$	473		$	(94	)

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 decreased $37 million and $18 million for the quarter and year-to-date, respectively. Core earnings decreased as rate base growth was more than offset by higher income tax expense, including a $40 million benefit in the second quarter of 2010 from a change in tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program.

EMG's 2011 core earnings increased $2 million and decreased $86 million for the quarter and year-to-date, respectively. Results for the year-to-date were impacted by the Homer City outage, lower realized energy prices, higher plant maintenance expenses and lower trading income. In addition, unrealized gains were $5 million for the first six months of 2011 compared to unrealized losses of $17 million in the same period last year.

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Consolidated non-core items for Edison International included:

•

An earnings benefit of $138 million recorded in the second quarter of 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement.

•

An after tax earnings charge of $39 million recorded in the first quarter of 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 six months of 2011, SCE's capital investment program focused on upgrading and expanding SCE's transmission and distribution system; replacing generation asset equipment; and installing smart meters. Total capital expenditures (including accruals) were $1.6 billion during the first six months of 2011 compared to $1.5 billion 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.

In July 2011, the FERC adopted new rules that remove incumbent public utility transmission owners' federally-based right of first refusal to construct certain new transmission facilities. The rules direct regional entities, such as ISOs, to create new processes that would allow other providers to develop new transmission projects. The new processes will not become effective until approved by FERC, which is expected in late 2012. The majority of SCE's 2011 - 2014 transmission capital forecast relates to transmission projects that have been approved by the CAISO and barring a re-evaluation under the new rules, will not be subject to the new processes. The impact of the new rules on future transmission projects will depend on the processes ultimately implemented by regional entities.

2012 CPUC General Rate Case

As discussed in the year-ended 2010 MD&A, SCE filed its GRC application in November 2010. In July 2011, SCE submitted rebuttal testimony in response to intervenor recommendations and updated its requested 2012 base rate revenue requirement to $6.2 billion to reflect agreement on certain issues identified in intervenor testimony. SCE's updated request, after considering the effects of sales growth, would result in incremental customer base rate increases of $794 million, $155 million and $515 million in 2012, 2013 and 2014, respectively. The updated request also reflects a previously submitted base revenue requirement reduction of $38 million, $133 million and $145 million in 2012, 2013, and 2014, respectively, primarily due to a reduction in rate base from inclusion of higher deferred income taxes resulting from bonus depreciation deductions under the 2010 Tax Relief Act.

The Division of Ratepayer Advocates ("DRA") recommended that SCE's requested 2012 base rate revenue requirement be decreased by approximately $850 million, comprised of approximately $630 million in operation and maintenance expense reductions and approximately $220 million in capital-related revenue requirement reductions. The Utility Reform Network or TURN and other intervenors recommended an additional $610 million revenue requirement reduction, beyond the DRA adjustments, primarily capital-related in nature, as well as disallowances of recorded capital costs for specific projects. Intervenors have also recommended changes to SCE's proposed post test year ratemaking methodology to be used for 2013 and 2014.

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. SCE cannot predict the revenue requirement the CPUC will ultimately authorize.

45

FERC Formula Rates

In August 2011, the FERC accepted SCE's request to implement a formula rate, effective January 1, 2012, to determine SCE's FERC transmission revenue requirement, including its construction work in progress ("CWIP") incentive revenue requirement that was previously recovered through a separate mechanism, subject to refund and settlement procedures. The FERC reduced SCE's proposed base ROE request from 11.5% to 9.93% (before adding the previously authorized 50 basis point incentive for CAISO participation and individual authorized project incentives). SCE's request proposed the adoption of a specific formula to calculate a forecast revenue requirement that is used to establish rates and is trued-up annually to allow SCE to recover its actual revenue requirement, including its actual cost of service, actual rate base (including the impact of bonus depreciation) and the authorized return on investment. SCE's request also allows SCE to make single-issue rate filings requesting changes to certain elements of the formula, including the base ROE, depreciation rates and the retail rate structure. The FERC order directs SCE to modify its 2012 forecast transmission revenue requirement of $771 million for the lower base ROE. SCE expects to file a request for rehearing of the adopted base ROE within 30 days and cannot predict the formula rate structure or the base ROE that the FERC will ultimately authorize.

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 March 2011 earthquake and tsunami, the NRC has been performing and plans to continue to perform additional operational and safety reviews of nuclear facilities in the United States. The NRC also created a Task Force to conduct a systematic review of U.S. NRC processes and regulations to determine whether additional improvements to the existing nuclear regulatory system are warranted in light of the events in Japan. The Task Force issued its initial report in July 2011, which concluded that a sequence of events like the Fukushima accident is unlikely to occur in the U.S., and that continued operation of U.S. reactors does not pose an imminent risk to public health and safety. The Task Force Report also included several proposed changes to regulations applicable to protection against natural phenomena, including earthquakes and flooding, and emergency preparedness. These recommendations must undergo additional review by NRC management and the nuclear industry before any changes are implemented; if implemented, they 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 compared to 2010 as a result of lower realized energy prices driven by the expiration of hedge contracts, higher fuel costs and outages at the Homer City plant during the first half of 2011. In addition, the profitability of EMG's Midwest Generation plants is expected to be adversely affected beginning 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), and EMG's Homer City plant is expected to be adversely impacted by new environmental regulations discussed further below. As a result, EMG may incur net losses during 2011 and in subsequent years unless energy and capacity prices increase or its costs decline.

At June 30, 2011, EMG and its subsidiaries had $870 million in cash and cash equivalents and $945 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 June 30, 2011, $500 million of which mature in 2013. EMG's business plans are focused on operating effectively through the current commodity price cycle, environmental compliance and energy project development plans.

Cross-State Air Pollution Rule

On July 6, 2011, the US EPA adopted its final CSAPR which will replace the CAIR beginning on January 1, 2012. CSAPR is the final form of a previously proposed replacement for the CAIR, called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual SO₂ emissions and annual and ozone season NO_x emissions in two phases: a first phase effective January 1,

46

2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO₂ emissions.

CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO₂ or NO_x emissions from operations will need to be matched by a sufficient amount of SO₂ or NO_x allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO₂ and NO_x allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual compliance period, units must surrender allowances for each ton of SO₂ and NO_x emitted or face penalties. While trading of allowances is permitted within designated groups of states, the rule provides for enhanced penalties against a unit that surrenders allowances in excess of certain predefined limits for itself and for the state in which it is located.

The installation of SO₂ controls will require capital commitments for the Midwest Generation plants well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. EMG believes that Midwest Generation's current environmental remediation plan, including allocated allowances and capital expenditures, required to meet the CPS will also comply with the requirements of CSAPR. However, the SO₂ allowances allocated to Homer City in CSAPR Phase I (25,797 tons in 2012 and 2013) are significantly lower than the amount that would be required based on Homer City's historical emissions (2010 SO₂ emissions were 112,951 tons). Therefore, pending installation of additional equipment for Units 1 and 2 (Homer City's Unit 3 is equipped with a wet scrubber flue gas desulfurization system to meet environmental standards), Homer City expects that it will be required to procure additional allowances. It is unclear at this time whether SO₂ allowances in sufficient quantity and at prices that Homer City can pass through in power prices will be available in 2012 and 2013. Also, Homer City's SO₂ shortfall is expected to exceed limits on the number of allowances it will be permitted to surrender, and, therefore, may subject Homer City to penalties in certain cases. Accordingly, Homer City is evaluating alternative options, including reduced dispatch and fuel switching, for complying with Phase I of CSAPR. Failure by Homer City to develop and implement a Phase I compliance plan based on allowances could result in its modifying operations at one or more units or significantly curtailing power output. The cost of allowances, together with possible operational impacts or reductions of output, which may be required to comply with Phase I of CSAPR, could have a material effect on Homer City.

Homer City has begun work on designing SO₂ and particulate emissions control equipment for Units 1 and 2. While the Phase II SO₂ emission allowances under CSAPR (11,068 tons) are less than were contemplated under the proposed Clean Air Transport Rule, the additional reductions are not expected to materially change the design for the SO₂ controls at Units 1 and 2. The installation of those SO₂ controls will require capital commitments for the Homer City plant well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. Given the relatively short period of time before Phase II of CSAPR takes effect in 2014, there is no assurance that Homer City will be able to complete all the work that will be required before the deadline. Homer City is continuing to review technologies available to reduce SO₂ and mercury emissions; however, it has not determined the most effective and efficient technology to meet all requirements that may be imposed on it. Consequently, the timing, selection of technology and ultimate capital costs remain uncertain. Based on preliminary estimates, Homer City currently believes the cost of such equipment may be between $600 million and $700 million.

In March 2011, the US EPA issued proposed National Emission Standards for Hazardous Air Pollutants, limiting emissions of hazardous air pollutants from coal- and oil-fired electrical generating units. This regulation is expected to be finalized by November 2011. Based on its continuing review, EME does not expect these standards, if adopted as proposed, would require Homer City to make additional capital requirements beyond those that would be required to comply with CSAPR.

Homer City Capital Needs

Homer City does not currently have sufficient capital and does not expect to generate sufficient funds from operations to complete retrofits effectively required by CSAPR Phase II. EME is under no legal obligation to provide funding and has chosen not to. Accordingly, Homer City will need third-party capital to undertake the retrofits required by 2014 under CSAPR. However, restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Consequently, the installation of environmental compliance equipment will be dependent on lessors, holders of the pass-through certificates and new providers of capital funding. Homer City has commenced discussions with

47

its lessors concerning such matters. There can be no assurance that Homer City will be able to raise the financing necessary to install the required SO₂ control equipment in a timely manner or on terms that will not result in a significant dilution of its interest in the Homer City plant.

Failure of Homer City to install the required equipment or determine an economic manner to continue plant operations could result in a loss of its lease and a cessation of plant operations. Cessation of plant operations or a significant reduction of the value of Homer City's interest in the plant could have a material adverse effect on future financial results, cash flow, financial flexibility and assets of EME compared to historical levels. At June 30, 2011, the book value of EME's investment in Homer City was approximately $1.1 billion.

Midwest Generation Environmental Compliance Plans and Costs

During 2011, Midwest Generation continued its permitting and planning activities for NO_x and SO₂ controls to meet the requirements of the CPS. Midwest Generation does not anticipate a material change to its current approach in order to comply with CSAPR. Based on its continuing review, EME also does not expect the US EPA issued proposed National Emission Standards for Hazardous Air Pollutants, 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 SO₂ as well as for HAPs, such as mercury, acid gas and non-mercury metals. Based on stack tests performed at various Midwest Generation plants, Midwest Generation believes that currently installed activated carbon injection and particulate removal equipment is sufficient to achieve or exceed the mercury standards outlined in the US EPA's existing and proposed rules. Midwest Generation does not anticipate a material change to its current approach in order to comply with CSAPR.

In February 2011, the Illinois EPA 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. Midwest Generation had previously received construction permits for dry sorbent injection installation at Waukegan Station's Unit 7.

Decisions regarding whether or not to proceed with retrofitting units to comply with CPS requirements for SO₂ 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 Midwest Generation may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. 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, subject to the requirements of the CPS and other applicable regulations.

Walnut Creek Project

In March 2008, Walnut Creek Energy, a subsidiary of EMG, was awarded a 10-year power sales agreement starting in 2013 for the output from its planned Walnut Creek project, a 479 MW natural gas-fired peaker plant in southern California. The contract was issued by SCE, through a competitive bidding process. Construction began on the Walnut Creek project in June 2011. The Walnut Creek project has estimated construction costs of $575 million and is expected to achieve commercial operation in 2013. In July 2011, Walnut Creek Energy completed non-recourse financings to fund the Walnut Creek project. The Walnut Creek construction loans, including the project level and intermediate holding company loans, have an effective interest rate of 3.11% including the impact of interest rate swaps through May 31, 2013. For more information, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Project Financings—Walnut Creek."

Environmental Regulation Developments

For additional discussion of environmental regulation developments regarding proposed Hazardous Air Pollutant Regulations, Cross-State Air Pollution Rule, Once-Through Cooling Issues, Greenhouse Gas Regulation and Greenhouse Gas Litigation Developments, 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 review of reasonableness or compliance with upfront standards, 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.

The following tables summarize SCE's results of operations for the periods indicated. The presentation separately identifies utility earning activities and utility cost-recovery activities.

Three Months Ended June 30, 2011 versus June 30, 2010

		Three months ended June 30, 2011								Three months ended June 30, 2010
(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated
Operating revenue		$	1,383		$	1,063	$	2,446		$	1,308		$	939	$	2,247
Fuel and purchased power			—			732		732			—			706		706
Operations and maintenance			549			297		846			537			218		755
Depreciation, decommissioning and amortization			323			33		356			306			14		320
Property taxes and other			68			1		69			61			1		62
Total operating expenses			940			1,063		2,003			904			939		1,843
Operating income			443			—		443			404			—		404
Net interest expense and other			(89	)		—		(89	)		(85	)		—		(85	)
Income before income taxes			354			—		354			319			—		319
Income tax expense			128			—		128			5			—		5
Net income			226			—		226			314			—		314
Dividends on preferred and preference stock			15			—		15			13			—		13
Net income available for common stock		$	211		$	—	$	211		$	301		$	—	$	301
Core Earnings1							$	211							$	248
Non-Core Earnings:
	Global Settlement							—								53
	Tax impact of health care legislation							—								—
Total SCE GAAP Earnings							$	211							$	301

¹

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

49

Utility Earning Activities

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $75 million primarily due to the following:

•

$40 million increase primarily due to a 4.35% increase in 2011 authorized revenue approved in the CPUC 2009 GRC decision.

•

$25 million increase in FERC-related revenue primarily due to CWIP incentive revenue 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 transmission and distribution expenditures.

•

Higher income taxes primarily due to a change in tax method of accounting for asset removal costs. See "—Income Taxes" below for further information.

Utility Cost-Recovery Activities

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

•

Higher purchased power expense of $37 million driven by higher average renewable energy contract prices resulting from new contracts entered into to meet the renewable procurement standard requirements, and by increased purchases in 2011 to replace power previously delivered under CDWR contracts which have since expired.

•

Higher operation and maintenance expense of $79 million resulting primarily from increased energy efficiency program costs.

•

Higher depreciation, decommissioning and amortization expense of $19 million primarily related to the steam generator replacement project and the EdisonSmartConnect™ project.

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Six Months Ended June 30, 2011 versus June 30, 2010

		Six months ended June 30, 2011								Six months ended June 30, 2010
(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated
Operating revenue		$	2,746		$	1,932	$	4,678		$	2,573		$	1,833		$	4,406
Fuel and purchased power			—			1,317		1,317			—			1,395			1,395
Operations and maintenance			1,078			553		1,631			1,057			411			1,468
Depreciation, decommissioning and amortization			641			59		700			605			24			629
Property taxes and other			143			3		146			129			1			130
Total operating expenses			1,862			1,932		3,794			1,791			1,831			3,622
Operating income			884			—		884			782			2			784
Net interest expense and other			(171	)		—		(171	)		(157	)		(2	)		(159	)
Income before income taxes			713			—		713			625			—			625
Income tax expense			251			—		251			134			—			134
Net income			462			—		462			491			—			491
Dividends on preferred and preference stock			29			—		29			26			—			26
Net income available for common stock		$	433		$	—	$	433		$	465		$	—		$	465
Core Earnings1							$	433								$	451
Non-Core Earnings:
	Global Settlement							—									53
	Tax impact of health care legislation							—									(39	)
Total SCE GAAP Earnings							$	433								$	465

¹

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

Utility Earning Activities

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $173 million primarily due to the following:

•

$80 million increase primarily due to a 4.35% increase in 2011 authorized revenue approved in the CPUC 2009 GRC decision.

•

$60 million increase in FERC-related revenue primarily due to CWIP incentive revenue for the Tehachapi transmission project and the implementation of the 2010 FERC rate case effective March 1, 2010.

•

$30 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 $36 million primarily related to increased transmission and distribution expenditures.

•

Higher net interest expense and other of $14 million primarily due to higher outstanding balances on long-term debt.

•

Higher income taxes primarily due to a change in tax method of accounting for asset removal costs. See "—Income Taxes" below for more information.

51

Utility Cost-Recovery Activities

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

•

Lower purchased power expense of $62 million driven by reduced purchases resulting from increased utility owned generation production in 2011, as compared to 2010, primarily due to 2010 outages at San Onofre and Four Corners. The decrease was partially offset by higher average renewable energy contract prices resulting from new contracts entered into to meet the renewable procurement standard requirements, and by increased purchases in 2011 to replace power previously delivered under CDWR contracts which have since expired.

•

$16 million decrease in fuel expense primarily due to lower production at Mountainview in 2011, partially offset by lower nuclear fuel expense in 2010 resulting from the San Onofre Unit 2 extended outage.

•

Higher operation and maintenance expense of $142 million resulting primarily from increased energy efficiency program costs.

•

Higher depreciation, decommissioning and amortization expense of $35 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 $2.4 billion and $4.5 billion for the three- and six-month periods ended June 30, 2011, respectively, compared to $2.4 billion and $4.4 billion for the respective periods in 2010. The year-to-date increase reflects a rate increase of $40 million and a sales volume increase of $60 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 a CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk or benefit related to retail electricity sales (see "Item 1. Business—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 $280 million and $555 million for the three- and six-month periods ended June 30, 2011, respectively, and $286 million and $582 million for the respective periods in 2010. 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 CDWR operating reserves are fully refunded. The power contracts that CDWR allocated to SCE will terminate by the end of 2011; however, the refund of operating reserves is expected to continue through 2012. 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.

52

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 June 30,						Six months ended June 30,
(in millions)			2011			2010			2011			2010
Income before income taxes			$	354		$	319		$	713		$	625
Provision for income tax at federal statutory rate of 35%			$	124		$	112		$	249		$	219
Increase (decrease) in income tax from:
	Items presented with related state income tax, net
		Global settlement related1		—			(53	)		—			(53	)
		Change in tax accounting method for asset removal costs2		—			(40	)		—			(40	)
	State tax – net of federal benefit			18			19			30			21
	Health care legislation3			—			—			—			39
	Property-related and other			(14	)		(33	)		(28	)		(52	)
Total income tax expense			$	128		$	5		$	251		$	134
Effective tax rate				36%			2%			35%			21%

¹

During the second quarter of 2010, SCE recognized a $53 million earnings benefit resulting from the acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement.

²

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

³

During the first quarter of 2010, SCE 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 decreased benefit provided by property-related and other items was primarily due to lower deductions for internally developed software in 2011 compared to the respective periods in 2010.

For a discussion of the status of Edison International's income tax audits, see "Edison International Notes to Consolidated Financial Statements—Note 7. Income Taxes."

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 June 30, 2011, SCE had approximately $46 million of cash and equivalents and short-term investments. SCE had two credit facilities: a $2.4 billion five-year credit facility that matures in February

53

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		(71	)
Amount available	$	2,623

Debt Covenant

SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At June 30, 2011, SCE's debt to total capitalization ratio was 0.47 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 June 30, 2011, SCE's 13-month weighted-average common equity component of total capitalization was 50.7% resulting in the capacity to pay $460 million in additional dividends.

During the first six months of 2011, SCE made $230 million in dividend payments 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

Certain derivative instruments, power procurement contracts and other contractual arrangements 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 June 30, 2011.

(in millions)
Collateral posted as of June 30, 20111	$	86
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade		71
Posted and potential collateral requirements2	$	157

¹

Collateral provided to counterparties and other brokers consisted of $1 million which was offset against net derivative liabilities and $85 million, which consisted of $14 million in cash reflected in "Other current assets" on the consolidated balance sheets and $71 million in letters of credit.

²

Total posted and potential collateral requirements may increase by an additional $20 million, based on SCE's forward positions as of June 30, 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 June 30, 2011, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $201 million for its workers compensation self-insurance plan.

54

Historical Consolidated Cash Flows

Condensed Consolidated Statement of Cash Flows

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

	Six months ended June 30,
(in millions)	2011			2010
Net cash provided by operating activities	$	1,385		$	1,095
Net cash provided by financing activities		491			465
Net cash used by investing activities		(2,091	)		(1,937	)
Net decrease in cash and cash equivalents	$	(215	)	$	(377	)

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased $290 million in the first six months of 2011 compared to the first six months of 2010. The increase reflects higher receipts from customers due to increases in authorized revenue and lower tax payments resulting from bonus depreciation. These increases were partially offset by net cash outflows related to regulatory balancing account activities. The operating cash flows were also impacted by the timing of cash receipts and disbursements related to working capital.

Net Cash Provided by Financing Activities

Net cash provided by financing activities for the first six months of 2011 was $491 million consisting of the following significant events:

•

Issued $500 million of 3.875% first and refunding mortgage bonds due in 2021. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.

•

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. The proceeds from the issuance were used for general corporate purposes.

•

Paid $230 million of dividends to Edison International.

•

Purchased $56 million of its tax-exempt bonds that were subject to remarketing.

Net cash provided by financing activities for the first six months of 2010 was $465 million consisting of the following significant events:

•

Reissued $144 million of tax-exempt pollution control bonds due in 2035. The proceeds from these bonds were used to repay commercial paper borrowings and for general corporate purposes.

•

Issued $500 million of first refunding mortgage bonds due in 2040. The bond proceeds were used to repay commercial paper borrowings and for general corporate purposes.

•

Issued $215 million of short-term debt to fund interim working capital requirements.

•

Repaid $250 million of senior unsecured notes.

•

Paid a $100 million dividend to Edison International.

55

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 $2.0 billion and $1.8 billion for the six months ended June 30, 2011 and 2010, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $84 million and $97 million for the six months ended June 30, 2011 and 2010, respectively.

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 June 30, 2011, SCE had 24 identified material sites for remediation and recorded an estimated minimum liability of $54 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 to mitigate SCE's exposure to commodity price risk was a net liability of $532 million and $207 million at June 30, 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,

56

including master netting agreements. As of June 30, 2011, the amount of balance sheet exposure as described above, by the credit ratings of SCE's counterparties, was as follows:

		June 30, 2011
(in millions)		Exposure2		Collateral			Net Exposure
S&P Credit Rating1
	A or higher	$	130	$	—		$	130
	A-		9		—			9
	Not rated3		41		(31	)		10
Total		$	180	$	(31	)	$	149

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 $4 million of net accounts receivable and $176 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

57

EDISON MISSION GROUP

RESULTS OF OPERATIONS

Results of Continuing Operations

This section discusses operating results for the three- and six-month periods ended June 30, 2011 and 2010. EMG's continuing operations include the coal plants, renewable energy and gas-fired projects and energy trading. EMG's discontinued operations include all international operations, except the Doga project.

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

		Three months ended June 30,						Six months ended June 30,
(in millions)		2011			2010			2011			2010
Competitive power generation operating revenues		$	538		$	495		$	1,090		$	1,147
Fuel			174			160			356			374
Operation and maintenance			329			316			610			566
Depreciation and amortization			79			60			152			120
Other			8			3			8			7
Total operating expenses			590			539			1,126			1,067
Operating income (loss)			(52	)		(44	)		(36	)		80
Interest and dividend income			27			4			29			24
Equity in income from unconsolidated affiliates – net			17			20			12			39
Other income, net			3			1			6			—
Interest expense			(80	)		(66	)		(160	)		(133	)
Income (loss) from continuing operations before income taxes			(85	)		(85	)		(149	)		10
Benefit for income tax			(55	)		(111	)		(101	)		(86	)
Income (loss) from continuing operations			(30	)		26			(48	)		96
Income (loss) from discontinued operations – net of tax			(1	)		1			(3	)		8
Net income (loss)			(31	)		27			(51	)		104
Less: Net income attributable to noncontrolling interests			—			—			—			—
Net income (loss) available for common shareholder		$	(31	)	$	27		$	(51	)	$	104
Core Earnings (Losses)1		$	(30	)	$	(32	)	$	(48	)	$	38
Non-Core Earnings (Losses)
	Global Settlement		—			58			—			58
	Discontinued Operations		(1	)		1			(3	)		8
Total EMG GAAP Earnings (Losses)		$	(31	)	$	27		$	(51	)	$	104

¹

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

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

•

$26 million higher income from a distribution received from the Doga project during the second quarter of 2011, with no comparable amount in 2010.

•

$10 million increase in energy trading revenues due to higher congestion and power trading revenues.

•

$5 million increase in renewable energy adjusted operating income due to the increase in wind projects in operation and higher generation from existing wind projects.

These increases were partially offset by the following:

•

$13 million decrease in Midwest Generation adjusted operating income due to lower average realized energy prices and higher operating expenses due primarily to planned plant outages, partially offset by higher capacity revenues.

58

•

$10 million decrease in Homer City adjusted operating income due mostly to higher operating expenses primarily resulting from plant outages and higher coal costs. Partially offsetting the decrease were unrealized derivative gains of $2 million in 2011 compared to losses of $12 million in 2010.

•

$14 million increase in interest expense due to higher interest related to renewable project financings of $8 million and lower capitalized interest of $6 million.

EMG's core earnings for the six months ended June 30, 2011 were lower than core earnings for the six months ended June 30, 2010 primarily due to the following pre-tax items:

•

$45 million decrease in Midwest Generation adjusted operating income due to lower average realized energy prices, lower generation and higher operating expenses, partially offset by higher capacity revenues.

•

$63 million decrease in Homer City adjusted operating income due primarily to lower generation and higher operating expenses resulting from the Unit 1 and 2 outages. Unit 1 returned to service on April 5, 2011, and Unit 2 returned to service on May 25, 2011. In addition, partially offsetting the decrease were unrealized derivative gains of $5 million in 2011 compared to losses of $14 million in 2010.

•

$26 million increase in interest expense due to higher interest expense related primarily to renewable energy projects financings of $19 million and lower capitalized interest of $7 million.

•

$22 million decrease in energy trading revenue due to lower congestion and power trading revenues.

These decreases were partially offset by the following:

•

$16 million increase in renewable energy adjusted operating income due to the increase in wind projects in operation coupled with higher generation.

Non-core item for EMG included:

•

An earnings benefit of $58 million recorded in the second quarter of 2010 related to the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service in 2009 for tax years 1986 through 2002 as part of the federal settlement of tax disputes and a revision to the interest on federal disputed tax items. See "—Income Taxes" below for more information.

Adjusted Operating Income ("AOI")—Overview

The following section and table provide a summary of results of EMG's operating projects and corporate expenses for the second quarters of 2011 and 2010 and six months ended June 30, 2011 and 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

59

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

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Midwest Generation plants	$	(52	)	$	(39	)	$	3		$	48
Homer City plant1		(10	)		—			(26	)		37
Renewable energy projects		24			19			45			29
Energy trading1		41			31			56			78
Big 4 projects		9			12			11			16
Sunrise		6			7			(1	)		3
Doga		26			—			26			15
March Point2		—			—			—			17
Westside projects		(1	)		—			(1	)		1
Other projects		6			3			10			6
Leveraged lease income		2			1			3			2
Other operating income		2			2			2			1
		53			36			128			253
Corporate administrative and general		(33	)		(36	)		(69	)		(74	)
Corporate depreciation and amortization		(6	)		(4	)		(12	)		(8	)
AOI3	$	14		$	(4	)	$	47		$	171

¹

Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City.

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.

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

		Three months ended June 30,						Six months ended June 30,
(in millions)		2011			2010			2011			2010
AOI		$	14		$	(4	)	$	47		$	171
Less:
	Equity in income of unconsolidated affiliates		17			20			12			39
	Dividend income from projects		27			2			28			18
	Production tax credits		19			19			37			33
	Other income, net		2			(1	)		5			1
Operating Income (Loss)		$	(51	)	$	(44	)	$	(35	)	$	80

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Adjusted Operating Income from Consolidated Operations

Midwest Generation Plants

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

		Three months ended June 30,						Six months ended June 30,
(in millions)		2011			2010			2011		2010
Operating Revenues		$	280		$	281		$	631	$	660
Operating Expenses
	Fuel1		107			98			233		239
	Plant operations		164			167			282		265
	Plant operating leases		18			18			37		37
	Depreciation and amortization		29			28			58		56
	Asset retirements		9			2			9		3
	Administrative and general		5			7			11		12
	Total operating expenses		332			320			630		612
Operating Income (Loss)			(52	)		(39	)		1		48
Other Income			—			—			2		—
AOI		$	(52	)	$	(39	)	$	3	$	48
Statistics
	Generation (in GWh)		5,560			5,430			13,030		13,642

¹

Included in fuel costs were $0.4 million and $1 million during the second quarters of 2011 and 2010, respectively, and $2 million and $5 million during the six months ended June 30, 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 six months ended June 30, 2011 and 2010. Transfers of SO₂ emission allowances from Midwest Generation were none and $5 million during the six months ended June 30, 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 $13 million for the second quarter ended June 30, 2011, compared to the corresponding period of 2010. The second quarter decrease in AOI was attributable to lower energy revenues, higher fuel costs and higher operating expenses, partially offset by higher capacity revenues. The decline in energy revenues was due to lower average realized energy prices, partially offset by higher generation. The increase in fuel costs was due to higher generation and higher coal costs. The increase in operating expenses was due to higher maintenance and overhauls, including the retirement of equipment that was replaced as part of overhauls.

AOI from the Midwest Generation plants decreased $45 million for six months ended June 30, 2011, compared to the corresponding period 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 due 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 (losses) from hedge activities of $2 million and $(3) million for the second quarters of 2011 and 2010, respectively, and $2 million and $4 million for the six months ended June 30, 2011 and 2010, respectively. Unrealized gains (losses) in 2011 and 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 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 $2 million during the second quarters of 2011 and 2010, respectively, and $2 million and $7 million for the six months ended June 30, 2011 and

61

2010, respectively. Unrealized losses were 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 June 30,					Six months ended June 30,
(in millions)		2011			2010		2011			2010
Operating Revenues1		$	136		$	129	$	251		$	304
Operating Expenses
	Fuel2		63			57		115			127
	Plant operations		50			38		97			75
	Plant operating leases		26			27		51			52
	Depreciation and amortization		5			4		10			9
	Asset retirements		—			1		—			1
	Administrative and general		2			2		4			3
	Total operating expenses		146			129		277			267
Operating Income (Loss)			(10	)		—		(26	)		37
AOI		$	(10	)	$	—	$	(26	)	$	37
Statistics
	Generation (in GWh)		2,226			2,289		4,169			5,243

¹

Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City.

²

Included in fuel costs were $0.3 million and $1 million during the second quarters of 2011 and 2010, respectively, and $1 million and $5 million during the six months ended June 30, 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 SO₂ emission allowances to Homer City were none and $5 million during the six months ended June 30, 2011 and 2010, respectively. Transfers of NO_x emission allowances from Homer City were $0.4 million during each of the six months ended June 30, 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 $10 million for the second quarter ended June 30, 2011, compared to the corresponding period of 2010. The second quarter decrease in AOI was attributable to higher plant maintenance costs from outages at Units 1 and 2 and higher coal costs, partially offset by unrealized gains in 2011 compared to unrealized losses in 2010 related to hedge contracts.

AOI from the Homer City plant decreased $63 million for six months ended June 30, 2011, compared to the corresponding period of 2010. The 2011 decrease in AOI was attributable to lower energy revenues driven by lower generation and energy prices, and higher plant maintenance costs from outages at Units 1 and 2, partially offset by unrealized gains in 2011 compared to unrealized losses in 2010 related to hedge contracts and lower fuel costs. The decline in fuel costs was 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 $(12) million for the second quarters of 2011 and 2010, respectively, and $5 million and $(14) million for the six months ended June 30, 2011 and 2010, respectively. Unrealized gains in 2011 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. Unrealized losses in 2010 were attributable to the ineffective portion of forward and futures contracts. 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).

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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 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."

Renewable Energy Projects

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

		Three months ended June 30,				Six months ended June 30,
(in millions)		2011		2010		2011		2010
Operating Revenues		$	59	$	34	$	111	$	64
Production Tax Credits			19		19		37		33
			78		53		148		97
Operating Expenses
	Plant operations		18		12		36		24
	Depreciation and amortization		37		22		68		43
	Administrative and general		1		—		2		1
	Total operating expenses		56		34		106		68
Equity in income (loss) from unconsolidated affiliates			1		—		1		(1	)
Other Income			1		—		2		1
AOI1		$	24	$	19	$	45	$	29
Statistics
	Generation (in GWh)2		1,555		992		2,940		1,835

¹

AOI is equal to operating income (loss) under GAAP 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 1,336 GWh and 821 GWh in the second quarter of 2011 and 2010, respectively, and 2,536 GWh and 1,512 GWh in the six months ended June 30, 2011 and 2010, respectively.

AOI from renewable energy projects increased $5 million and $16 million in the second quarter and six months ended June 30, 2011, respectively, compared to the corresponding periods of 2010. The 2011 increases were 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.

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AOI from energy trading activities increased $10 million and decreased $22 million for the second quarter and six months ended June 30, 2011, compared to the corresponding periods of 2010. The second quarter and year-to-date variances were attributable to fluctuations in revenues from congestion and power trading, compared to the same prior-year periods.

Adjusted Operating Income from Unconsolidated Affiliates

Doga.    EMG received a distribution from the Doga project in the second quarter of 2011 and in the first quarter of 2010. AOI is recognized when cash is distributed from the project as the Doga project is accounted for on the cost method.

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

Kern River.    Kern River Cogeneration Company has entered into an extension of its power purchase agreement with Southern California Edison Company, which was set to expire in June 2011. EMG expects that this arrangement will eventually be replaced by a new power purchase agreement, but cannot predict whether a new agreement will be reached on acceptable terms or at all.

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 June 30,						Six months ended June 30,
(in millions)		2011			2010			2011			2010
Interest expense, net of capitalized interest
	EME debt	$	(63	)	$	(58	)	$	(125	)	$	(118	)
	Non-recourse debt		(17	)		(8	)		(35	)		(15	)
		$	(80	)	$	(66	)	$	(160	)	$	(133	)

EMG's interest expense increased primarily due to higher debt balances for wind project financing and lower capitalized interest. Capitalized interest for renewable energy projects under construction was $6 million and $16 million for the second quarter and six months ended June 30, 2011, respectively, compared to $12 million and $23 million for the second quarter and six months ended June 30, 2010, respectively.

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Income Taxes

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

		Three months ended June 30,						Six months ended June 30,
(in millions)		2011			2010			2011			2010
Income (loss) from continuing operations before income taxes		$	(85	)	$	(85	)	$	(149	)	$	10
Provision (benefit) for income taxes at federal statutory rate of 35%		$	(30	)	$	(30	)	$	(52	)	$	4
Increase (decrease) in income tax from:
	State tax – net of federal provision (benefit)		(4	)		(3	)		(9	)		1
	Tax credits, net		(19	)		(19	)		(37	)		(34	)
	Resolution of 1986-2002 state tax issues		—			(58	)		—			(58	)
	Other		(2	)		(1	)		(3	)		1
Total income tax benefit		$	(55	)	$	(111	)	$	(101	)	$	(86	)
Effective tax rate			65%			131%			68%			nm*

*  Not meaningful.

For a discussion of the status of Edison International's income tax audits, see "Edison International Notes to Consolidated Financial Statements—Note 7. Income Taxes."

LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

The following table summarizes available liquidity at June 30, 2011:

(in millions)		Cash and Cash Equivalents		Available Under Credit Facilities		Total Available Liquidity
EME as a holding company		$	237	$	448	$	685
EME subsidiaries without contractual dividend restrictions			195		—		195
EME corporate cash and cash equivalents			432		448		880
EME subsidiaries with contractual dividend restrictions
	Midwest Generation1		254		497		751
	Homer City		61		—		61
	Other EME subsidiaries		86		—		86
Other EMG subsidiaries			37		—		37
Total		$	870	$	945	$	1,815

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 operate 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."

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The following table summarizes the status of the EME and Midwest Generation credit facilities at June 30, 2011, which mature in June 2012:

(in millions)	EME			Midwest Generation
Commitments	$	564		$	500
Outstanding borrowings		—			—
Outstanding letters of credit		(116	)		(3	)
Amount available	$	448		$	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.

Homer City Outage

During the first half of 2011, Homer City Units 1 and 2 were off line due to a steam pipe rupture at Unit 1 and precautionary maintenance at Unit 2. While Unit 1 returned to service on April 5, 2011 and Unit 2 on May 25, 2011, the outages 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 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 arrangement 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. Homer City anticipates that the equity rent reserve balance will be restored in the future. At June 30, 2011, the equity rent reserve balance remained at the drawn balance of $8 million, but Homer City had delivered energy sufficient to eliminate the accelerated payments by EMMT. Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. Accordingly, since April 1, 2011, these revenues have been 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 of its sale-leaseback documents relating to the payment of equity rent at April 1, 2011. Under these documents, rent payments are comprised of two components, senior rent and equity rent. Senior rent is used exclusively for debt service to holders of senior secured bonds issued in connection with the sale-leaseback transaction, while equity rent is paid to the owner-lessors. In order to pay equity 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). Homer City is not subject to any minimum historical and projected senior rent service coverage ratios except as conditions to distributions and equity rent payments. For additional discussion regarding Homer City's liquidity, see "Edison International Management Overview—Management Overview of EMG—Cross-State Air Pollution Rule" and "—Homer City Capital Needs."

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Capital Investment Plan

At June 30, 2011, forecasted capital expenditures through 2013 by EMG's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

(in millions)		July through December 2011		2012		2013
Midwest Generation Plants
	Environmental1	$	49	$	172	$	317
	Plant capital		11		21		28
Homer City Plant
	Environmental1		—		—		—
	Plant capital		5		26		16
Walnut Creek Project			173		257		43
Renewable Energy Projects
	Capital and construction		72		—		—
	Turbine commitments		45		8		—
Other capital			7		14		14
Total		$	362	$	498	$	418

¹

For additional information, see "Edison International Management Overview—Management Overview of EMG—Cross-State Air Pollution Rule."

Environmental Capital Expenditures

Midwest Generation plants' environmental expenditures include $34 million for remaining expenditures in 2011 related to selective non-catalytic reduction (SNCR) equipment and $501 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 SO₂ emissions. EMG believes Midwest Generation's current environmental remediation plan, including allocated allowances and capital expenditures, required to meet the CPS will also comply with the requirements of CSAPR and the proposed National Emissions Standards for Hazardous Air Pollutants. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with CPS and other requirements, 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 that Homer City will be required to undertake to meet the requirements of CSAPR. The timing, selection of technology and ultimate capital costs remain uncertain. For a discussion of environmental regulations, see "Edison International Management Overview—Management Overview of EMG—Cross State Air Pollution Rule" and "—Homer City Capital Needs" in this MD&A, and "Item 1. Environmental Regulation of Edison International and Subsidiaries" and "Item 1A. Risk Factors—Risks Relating to EMG—Regulatory and Environmental Risks" in the 2010 Form 10-K.

Plant 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, and development of a coal-cleaning plant refuse site and a new ash disposal site.

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Funding of Capital Expenditures

In July, EME secured $495 million in construction and term financing for the Walnut Creek project. In addition, EME used the proceeds of the Laredo Ridge U.S. Treasury grant of $57 million received in July 2011 to repay the Laredo Ridge bridge loan. EME anticipates that the capital investment for renewable energy projects under construction will be funded using a combination of construction and term financings, U.S. Treasury grants and cash on hand. In addition to the U.S. Treasury grant received in July, U.S. Treasury grants of approximately $360 million are anticipated in 2011 and 2012 based on estimated eligible construction costs for renewable projects. For additional information on the Walnut Creek project, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Project Financings—Walnut Creek."

Renewable Energy Projects

In the second quarter of 2011, EMG acquired and commenced construction on the 55 MW Pinnacle wind project. The Community Wind North wind project achieved commercial operation on May 28, 2011, and the Taloga wind project achieved commercial operation on July 13, 2011.

The capital investment plan set forth in the previous table does not include capital expenditures for future projects. At June 30, 2011, EMG had a development pipeline of potential wind projects with projected installed capacity of approximately 3,900 MW. The development pipeline represents potential wind projects with respect to which EMG either owns the project rights or has exclusive acquisition rights. The pace of additional growth in EMG's renewable program will be subject to the availability of third-party equity capital. At June 30, 2011, EMG had capitalized costs and turbine deposits totaling $53 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.

Historical Segment Cash Flows

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

Condensed Statement of Cash Flows

	Six months ended June 30,
(in millions)	2011			2010
Operating cash flow from continuing operations	$	(79	)	$	(120	)
Operating cash flow from discontinued operations		(3	)		8
Net cash used by operating activities		(82	)		(112	)
Net cash provided (used) by financing activities		96			(52	)
Net cash used by investing activities		(242	)		(274	)
Net decrease in cash and cash equivalents	$	(228	)	$	(438	)

Net Cash Provided by Operating Activities

The decrease in the first six months of 2011 as compared to the first six months of 2010 in cash used by operating activities from continuing operations was primarily attributable to lower net income, a $253 million deposit paid by Edison Capital to the IRS in 2010 related to the Global Settlement, $92 million of U.S. Treasury grants received in 2010, and changes in other current liabilities.

Net Cash Provided by Financing Activities

The increase in the first six months of 2011 as compared to the first six months of 2010 in cash provided by financing activities from continuing operations was primarily attributable to additional wind project borrowings.

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Net Cash Provided by Investing Activities

Cash used in investing activities for the first six months of 2011 and 2010 primarily consisted of capital expenditures. In addition, cash used in investing activities for the first six months of 2011 included wind and gas project investments and other capital expenditures.

Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT as of June 30, 2011 were as follows:

	Moody's Rating	S&P Rating		Fitch Rating
EME1	Caa1		B-	CCC
Midwest Generation2	Ba3		B+	BB-
EMMT	Not Rated		B-	Not Rated

¹

Senior unsecured rating.

²

First priority senior secured rating.

On June 29, 2011, Moody's lowered the credit ratings of EME to Caa1 from B3 and Midwest Generation to Ba3 from Ba2. On June 30, 2011, Fitch lowered the credit ratings of EME to CCC from B- and Midwest Generation to BB- from BB. All the above ratings are on negative outlook. EME cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

EMG does not have any "rating triggers" contained in subsidiary financings that would result in a requirement 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, EME 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. EME has entered into guarantees in support of EMMT's hedging and trading activities; however, EME 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 June 30, 2011, if wholesale energy prices change or if EMMT enters into additional transactions. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—Debt Covenants and Dividend Restrictions."

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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
	June 30, 2011		December 31, 2010
Ratio		1.83		2.07
Covenant threshold (not less than)		1.20		1.20

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

	June 30, 2011		December 31, 2010
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 June 30, 2011 or for the 12 months ended June 30, 2011:

Subsidiary	Financial Ratio	Covenant	Actual
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		1.75 to 1

To make distributions, including repayment of certain intercompany loans, Homer City must meet the senior rent service coverage ratio. In addition, Homer City is restricted from making distributions until the Homer City equity reserve account is replenished. For additional information, see "Edison Mission Group—Liquidity and Capital Resources—Homer City Outage" in this MD&A.

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.

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

EME 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 June 30, 2011, the maximum permissible sale or disposition of EME assets was $888 million.

This limitation does not apply if the proceeds are invested in assets in similar or related lines of business of EME. Furthermore, EME may sell or otherwise dispose of assets in excess of such 10% limitation if the proceeds from such sales or dispositions, which are not reinvested as provided above, are retained as cash or cash equivalents or are used to repay debt.

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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."

Capital Expenditures

For a discussion of capital expenditures, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments—Capital Expenditures."

Midwest Generation New Source Review and Other Litigation

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 and Other Litigation."

Homer City New Source Review and Other Litigation

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

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 June 30,						Six months ended June 30,
(in millions)		2011			2010			2011			2010
Midwest Generation plants
	Non-qualifying hedges	$	2		$	(4	)	$	1		$	(6	)
	Ineffective portion of cash flow hedges		(1	)		(1	)		(1	)		3
Homer City plant
	Non-qualifying hedges		2			—			3			—
	Ineffective portion of cash flow hedges		—			(12	)		2			(14	)
Total unrealized gains (losses)		$	3		$	(17	)	$	5		$	(17	)

At June 30, 2011, cumulative unrealized gains of $8 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($3 million for the remainder of 2011 and $5 million for 2012).

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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.

Commodity Price Risk

Energy Price Risk

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 and Cinergy Hubs, all in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City plant. In addition, energy hedging transactions may be entered into using natural gas. Energy from 428 MW of merchant renewable energy projects is sold in the energy markets, primarily at spot prices in PJM and the Electric Reliability Council of Texas (ERCOT).

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

		24-Hour Average Historical Market Prices1
		2011		2010
Midwest Generation plants
	Northern Illinois Hub	$	34.50	$	33.44
Homer City plant
	PJM West Hub		46.52		43.88
	Homer City Busbar		42.45		38.28

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 June 30, 2011:

		24-Hour Forward Energy Prices1
		Northern Illinois Hub		PJM West Hub
2011
	July	$	36.43	$	51.14
	August		38.60		51.32
	September		29.83		43.39
	October		26.21		40.24
	November		29.67		40.84
	December		31.33		46.46
2012 calendar "strip"2			33.08		46.01

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

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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 contracts and forward contracts accounted for on the accrual basis) at June 30, 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/ MWh1		MWh (in thousands)		Average price/ MWh1		MWh (in thousands)		Average price/ MWh1
Midwest Generation plants2
	Northern Illinois		6,892	$	38.70		7,798	$	37.38		1,020	$	39.11
Homer City plant3,4
	PJM West Hub		2,002		56.34		1,340		51.66		204		51.85
Total			8,894				9,138				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 Northern Illinois Hub and to a lesser extent the AEP/Dayton and Cinergy Hubs.

³

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.

⁴

The average price/MWh includes 175 MW of capacity for periods ranging from July 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 June 30, 2011:

													Other Capacity Sales, Net of Purchases3
									RPM Capacity Sold in Base Residual Auction
		Installed Capacity MW		Unsold Capacity1 MW			Capacity Sold2 MW									Average Price per MW-day		Aggregate Average Price per MW-day
									MW		Price per MW-day		MW
July 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
June 1, 2014 to May 31, 2015
	Midwest Generation		5,477		(852	)		4,625		4,625		125.99		—			—		125.99
	Homer City		1,884		(190	)		1,694		1,694		136.50		—			—		136.50

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 175 MW of capacity for periods ranging from July 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 six months ended June 30, 2011 and 2010, prices at the Homer City busbar were lower than the PJM West Hub by an average of 9% and 13%, respectively, due to transmission congestion in PJM. During the six months ended June 30, 2011, prices at the individual busbars of the Midwest Generation plants were lower than the AEP/Dayton Hub, Cinergy Hub and Northern Illinois Hub by an average of 13%, 2% and 1%, respectively, compared to 11%, 2% and 1%, respectively, during the six months ended June 30, 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 June 30, 2011 for the remainder of 2011 and the following two years:

	Amount of Coal Under Contract in Millions of Equivalent Tons1
	July through December 2011		2012		2013
Midwest Generation plants2		8.9		11.7		—
Homer City plant		2.7		2.2		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.

²

In July 2011, Midwest Generation entered into additional contractual agreements for the purchase of coal of 0.5 million tons for the remainder of 2011, 2.0 million tons for 2012, 9.8 million tons for 2013, and 9.8 million tons for 2014.

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 SO₂ per MMBtu sulfur content) increased to a price of $78.20 per ton at July 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 SO₂ per MMBtu sulfur content) purchased for the Midwest Generation plants fluctuated between $12.35 per ton and $14.75 per ton during the first six months of 2011. The market price of PRB coal decreased to a price of $13.25 per ton at July 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 materially 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 SO₂ allowances sufficient to cover their annual emissions. Pursuant to Pennsylvania's and Illinois' implementation of the CAIR, which expires on December 31, 2011, 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 SO₂ allowances decreased to $7 per ton during the six months ended June 30, 2011 from $50 per ton in 2010. The average purchase price of annual NO_x allowances decreased to $244 per ton during the six months ended June 30, 2011 from $936 per ton in 2010. Based on broker's quotes and information from public sources, the spot price for SO₂ allowances and annual NO_x allowances was $4 per ton and $147.50 per ton, respectively, at June 30, 2011.

Under CSAPR, beginning January 1, 2012, the amount of SO₂ that a plant emits in its operation will need to be matched by a sufficient amount of SO₂ allowances designated under this program (CSAPR SO₂ allowances) that are either allocated to the plant under the CSAPR program or purchased in the open market. SO₂ allowances under the federal Acid Rain Program cannot be used to satisfy the requirements under CSAPR. EME will be impacted by market prices for additional CSAPR SO₂ allowances required, but availability and market prices are uncertain. For additional information on CSAPR, see "Edison International Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments—Cross-State Air Pollution Rule."

Credit Risk

The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EMG's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At June 30, 2011, the balance sheet exposure as described above, by the credit ratings of EMG's counterparties, was as follows:

		June 30, 2011
(in millions)		Exposure2		Collateral			Net Exposure
Credit Rating1
	A or higher	$	123	$	—		$	123
	A-		2		—			2
	BBB+		16		—			16
	BBB		1		—			1
	BBB-		14		—			14
	Below investment grade		32		(31	)		1
Total		$	188	$	(31	)	$	157

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 $113 million of net accounts receivable and payables and $76 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. 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 $50 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 66% of EMG's consolidated operating revenues for the six months ended June 30, 2011. At June 30, 2011, EMG's account receivable due from PJM was $73 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

75

subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to EMG's turbine suppliers may have a material impact on EMG's wind projects and development efforts.

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EMG mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. For details, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements," and refer to "Note 5 Debt and Credit Agreements" in Item 8 of Edison International's 2010 Form 10-K.

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EDISON INTERNATIONAL PARENT AND OTHER

RESULTS OF OPERATIONS

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

Edison International Parent and Other income (loss) from continuing operations was $(4) million and $16 million for the three months ended June 30, 2011 and 2010, respectively, and $(6) million and $11 million for the six months ended June 30, 2011 and 2010, respectively. Results for the three- and six-month periods ended June 30, 2010 included $27 million of consolidated tax benefits from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement. Results for the three- and six-month periods ended June 30, 2011 included consolidated tax benefits resulting from differences in state tax allocations to subsidiaries of income taxes under the tax allocation agreements of $5 million and $11 million, 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 June 30, 2011, Edison International (parent) had $19 million of cash and equivalents on hand. The following table summarizes the status of the Edison International (parent) credit facility at June 30, 2011:

(in millions)	Edison International (parent)
Commitment	$	1,426
Outstanding borrowings		(79	)
Outstanding letters of credit		—
Amount available	$	1,347

Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1. At June 30, 2011, Edison International's consolidated debt to total capitalization ratio was 0.54 to 1.

Historical Cash Flows

Condensed Statement of Cash Flows

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

	Six months ended June 30,
(in millions)	2011			2010
Net cash used by operating activities	$	(81	)	$	(21	)
Net cash provided by financing activities		79			25
Net cash provided by investing activities		1			7
Net increase (decrease) in cash and cash equivalents	$	(1	)	$	11

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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.

Net Cash Provided (Used) by Financing Activities

Financing activities for the first six months of 2011 were as follows:

•

Paid $209 million of dividends (or $0.64 per share) to Edison International common shareholders. In April 2011, the Board of Directors of Edison International declared a $0.32 per share quarterly dividend which is payable in July 2011.

•

Received $230 million of dividend payments from SCE.

•

Borrowed $60 million under Edison International's line of credit to fund interim working capital requirements.

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

•

Paid $205 million of dividends (or $0.63 per share) to Edison International common shareholders. In April 2010, the Board of Directors of Edison International declared a $0.315 per share quarterly dividend which was paid in July 2010.

•

Received $100 million of dividend payments from SCE.

•

Borrowed $130 million under Edison International's line of credit to fund interim working capital requirements.

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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 ("NOV Recipients") 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 April 2011, the NOV Recipients entered into a Consent Order with the Coastal Commission to resolve the NOV Recipients' liability to the Coastal Commission under the Coastal Act. On June 10, 2011, the NOV Recipients entered into a Settlement Agreement to resolve any remaining claims among themselves pertaining to the NOV.

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Navajo Nation Litigation

Developments related to the Navajo Nation litigation are discussed in "SCE Notes to Consolidated Financial Statements Note 9. Commitments and Contingencies—Contingencies—Navajo Nation Litigation."

Midwest Generation New Source Review and Other Litigation

Nine of ten PSD claims have been dismissed, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court has also dismissed all claims asserted against Commonwealth Edison Company 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 on June 3, 2013.

In May 2011, two complaints were filed against Midwest Generation in the Northern District of Illinois by residents living near the Crawford and Fisk facilities on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs seek to have their suits certified as a class action and request injunctive relief, as well as compensatory and punitive damages.

Homer City New Source Review and Other Litigation

In April 2011, Homer City filed motions to dismiss two complaints that were filed in January 2011 by the US EPA and two residents, respectively, in the Western District of Pennsylvania.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Period	(a) Total Number of Shares (or Units) Purchased1		(b) Average Price Paid per Share (or Unit)1		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1, 2011 to April 30, 2011		107,173	$	38.13		—		—
May 1, 2011 to May 31, 2011		621,653	$	39.57		—		—
June 1, 2011 to June 30, 2011		511,001	$	38.89		—		—
Total		1,239,827	$	39.17		—		—

¹

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

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ITEM 6. EXHIBITS

10.1	Edison International and Southern California Edison Company Director Compensation Schedule, as adopted June 23, 2011
10.2	Edison International 2007 Performance Incentive Plan, Amended and Restated as of February 24, 2011 (File 1-9936, filed as Exhibit 10.1 to Edison International's Form 8-K dated April 28, 2011 and filed April 29, 2011)*
31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32	Statement Pursuant to 18 U.S.C. Section 1350
101	Financial statements from the quarterly report on Form 10-Q of Edison International for the quarter ended June 30, 2011, filed on August 4, 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

*

Incorporated by reference pursuant to Rule 12b-32.

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SIGNATURE

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

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

Date: August 4, 2011

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EX-10.1

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Exhibit 10.1

EDISON INTERNATIONAL AND SOUTHERN CALIFORNIA EDISON COMPANY
DIRECTOR COMPENSATION SCHEDULE

As Adopted June 23, 2011

Effective July 1, 2011 and except as otherwise provided below, non-employee Directors of Edison International ("EIX") and/or Southern California Edison Company ("SCE") will receive the annual retainers, meeting fees, meeting expenses and equity-based awards described below as compensation for serving as a Director. The equity-based award provisions described below are effective for Directors elected or reelected on or after the date of the EIX 2012 annual shareholders' meeting.

Directors who are employees of EIX or SCE shall not receive additional compensation for serving as Directors (other than participation in the EIX Director Matching Gifts Program). Directors who serve on both the EIX Board and the SCE Board, and their corresponding Board Committees, will not receive additional compensation, including additional meeting fees for SCE Board, Board Committee and business meetings held concurrently or consecutively with a corresponding EIX Board, Board Committee or business meeting.

Annual Retainers

Board Retainer – Each Director will receive an annual board retainer of $55,000 to be paid in advance in quarterly installments of $13,750 for any calendar quarter or portion thereof during which the individual serves as a Director.

Board Committee Chair Retainer – Each Director who serves as the Chair of a Board Committee will receive an annual retainer of $10,000, except the Director who serves as the Chair of the Audit Committee will receive an annual retainer of $20,000 and the Director who serves as the Chair of the Compensation and Executive Personnel Committee will receive an annual retainer of $15,000. The Committee Chair retainers shall be paid in advance in equal quarterly installments for any calendar quarter or portion thereof during which the Director serves as a Committee Chair.

Lead Director Retainer – Each Director who serves as the lead director of the non-employee and/or independent Director executive sessions of the Board shall receive an annual retainer of $25,000. The retainer shall be paid in advance in equal quarterly installments for any calendar quarter or portion thereof during which the Director serves as a Lead Director.

The quarterly retainer installments will be paid on the first business day of the calendar quarter. Initial quarterly retainer installments will be paid as soon as possible following the date of the election.

Meeting Fees

Each Director will receive $2,000 for each regular meeting, adjourned regular meeting or special meeting of the Board attended by the Director, for each regular meeting,

adjourned regular meeting or special meeting of a Committee attended by the Director as a member of the Committee, and for each business meeting attended at the request or invitation of the Chairman of the Board, or in the case of Committee meetings at the request or invitation of the Chairman of the Board in consultation with the Committee Chair on behalf of the corporation in his or her capacity as a Director. Each Director shall receive only one meeting fee for any concurrent meeting attended by the Director, including concurrent meetings of different Board Committees. Full meeting fees will be paid if the Director attends any portion of any meeting.

No additional meeting fee shall be paid when the non-employee or independent members of the Board meet in executive session immediately before, during or immediately after Board meetings.

Meeting fees will be paid on the first business day of the month following the month in which the meeting occurred.

Meeting Expenses

Reasonable expenses incurred by a Director to attend Board meetings, Committee meetings, or business meetings attended on behalf of the corporation in his or her capacity as a Director will be promptly reimbursed upon presentation of a statement of the expenses to the Secretary.¹

Equity-Based Awards²

Equity-based awards ("Awards") will be granted under and subject to the terms of the EIX 2007 Performance Incentive Plan, or a successor plan (the "Plan"), except that any award payable in cash will be deemed paid outside of the plan. The Awards consist of fully vested Edison International deferred stock units ("DSUs") and/or Edison International common stock ("Common Stock"). DSUs represent the value of one share of Common Stock and will be credited to the Director's account under the EIX Director Deferred Compensation Plan and subject to the terms of that plan. DSUs include dividend equivalent rights that are converted to additional DSUs. The number of DSUs or shares of Common Stock awarded to a Director in any particular instance will be calculated by dividing the applicable equity award amount to be granted on that date (expressed in dollars and determined as set forth below, the "Award Amount") by the fair market value of a share of Common Stock as of that date, rounded up to the nearest whole share. Fair market value for these purposes shall be determined in accordance with the Plan. Each Award will be subject to terms and conditions approved in advance by the Board.

¹

To the extent any expense reimbursements provided for in this Director Compensation Schedule are taxable to a Director and provide for a deferral of compensation within the meaning of Section 409A of the Internal Revenue Code, the Director shall complete all steps required for reimbursement so as to facilitate payment, and any such reimbursements shall be paid to the Director on or before December 31 of the calendar year following the calendar year in which the expense was incurred. Such reimbursements shall not be subject to liquidation or exchange for other benefits, and the expenses eligible for reimbursement in one calendar year shall not affect the expenses eligible for reimbursement in any other calendar year. The requirements of this footnote shall be effective on December 31, 2008.

²

With respect to equity-based awards approved and granted under current and prior compensation plans by prior resolutions of the EIX Board, this Director Compensation Schedule does not alter the intent of such resolutions to have the awards and subsequent transactions by the Directors occurring pursuant to the awards continue to comply with and be exempt under Rule 16b-3 (or any successor provision thereto).

2

Initial Election Award – Upon the initial election of a Director to the Board, the Director will receive an award of DSUs with an aggregate Award Amount of $105,000, the date of grant of which shall be the date of such election.

Annual Reelection Award – Each Director reelected to the Board will receive Common Stock and/or DSUs with an aggregate Award Amount of $105,000, the date of grant of which shall be the date of such reelection. The portion of the award to be granted in Common Stock and/or DSUs shall be specified in advance by the Director as provided in the next paragraph.

Prior to the year the Annual Reelection Award is granted, the Director may elect to receive the award entirely in shares of Common Stock, entirely in DSUs, or in any combination of each, except that if a fractional share would result, the Common Stock portion will be rounded up to the next whole share and the DSU portion will be rounded down to the next whole DSU. If no such election is timely made by the Director for a particular year, the Director's Annual Reelection Award (if any) for that year will be entirely Common Stock.

EIX Affiliate Boards – SCE non-employee Directors who do not serve on the EIX Board will receive Awards equal in amount to EIX non-employee Directors if the SCE Board authorizes such compensation. Differing amounts of SCE Awards, and Awards for non-employee directors of other EIX affiliates, may only be made with additional approval of the EIX Board.

Matching Gift Program

Directors of EIX and SCE are eligible to participate in the EIX Director Matching Gifts Program.

3

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Exhibit 10.1

EDISON INTERNATIONAL AND SOUTHERN CALIFORNIA EDISON COMPANY DIRECTOR COMPENSATION SCHEDULE As Adopted June 23, 2011

EX-31.1

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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 June 30, 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: August 4, 2011

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

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Exhibit 31.1

CERTIFICATION

EX-31.2

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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 June 30, 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 15(d)-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: August 4, 2011

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

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Exhibit 31.2

CERTIFICATION

EX-32

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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 June 30, 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: August 4, 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.

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Exhibit 32

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Compensation and Benefit Plans (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Pension and Other Postretirement Benefits
Additional plan year contributions			$ 44
Employer contributions			12
Pension Plans
Pension and Other Postretirement Benefits
Additional plan year contributions			69
Employer contributions			61
Expense components are:
Service cost	43	34	86	68
Interest cost	52	54	104	108
Expected return on plan assets	(60)	(52)	(120)	(104)
Amortization of prior service cost (credit)	2	2	4	4
Amortization of net loss	6	7	12	14
Expense under accounting standards	43	45	86	90
Regulatory adjustment - deferred	(6)	(14)	(12)	(28)
Total expense recognized	37	31	74	62
Postretirement Benefits Other Than Pensions
Expense components are:
Service cost	11	8	22	16
Interest cost	33	31	66	62
Expected return on plan assets	(28)	(25)	(56)	(50)
Amortization of prior service cost (credit)	(9)	(9)	(18)	(18)
Amortization of net loss	9	8	18	16
Total expense recognized	$ 16	$ 13	$ 32	$ 26

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Consolidated Statements of Comprehensive Income
Net gain arising during the period, income tax expense				$ 2
Amortization of net (gain) loss included in net income, income tax expense (benefit)	1	1	3	(4)
Prior service credit arising during the period, income tax expense				1
Amortization of prior service credit, income tax benefit				1
Unrealized holding gain (loss) arising during the period, income tax expense (benefit)	(9)	(50)	(5)	12
Reclassification adjustments included in net income, income tax benefit	$ 6	$ 35	$ 12	$ 49

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Consolidated Balance Sheets (USD $) In Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
ASSETS
Cash and cash equivalents	$ 945	$ 1,389
Receivables, less allowances of $87 and $85 for uncollectible accounts at respective dates	1,018	931
Accrued unbilled revenue	619	442
Inventory	589	568
Prepaid taxes	356	390
Derivative assets	117	133
Restricted cash	11	2
Margin and collateral deposits	65	65
Regulatory assets	469	378
Other current assets	148	124
Total current assets	4,337	4,422
Nuclear decommissioning trusts	3,657	3,480
Investments in unconsolidated affiliates	552	559
Other investments	231	223
Total investments	4,440	4,262
Utility property, plant and equipment, less accumulated depreciation of $6,486 and $6,319 at respective dates	25,847	24,778
Competitive power generation and other property, plant and equipment, less accumulated depreciation of $2,009 and $1,865 at respective dates	5,613	5,406
Total property, plant and equipment	31,460	30,184
Derivative assets	242	437
Restricted deposits	27	47
Rent payments in excess of levelized rent expense under plant operating leases	1,288	1,187
Regulatory assets	4,690	4,347
Other long-term assets	591	644
Total long-term assets	6,838	6,662
Total assets	47,075	45,530
LIABILITIES AND EQUITY
Short-term debt	388	115
Current portion of long-term debt	53	48
Accounts payable	1,110	1,362
Accrued taxes	33	52
Accrued interest	225	205
Customer deposits	208	217
Derivative liabilities	238	217
Regulatory liabilities	820	738
Other current liabilities	807	998
Total current liabilities	3,882	3,952
Long-term debt	12,956	12,371
Deferred income taxes	5,819	5,625
Deferred investment tax credits	132	122
Customer advances	121	112
Derivative liabilities	580	468
Pensions and benefits	2,306	2,260
Asset retirement obligations	2,616	2,561
Regulatory liabilities	4,759	4,524
Other deferred credits and other long-term liabilities	2,147	2,041
Total deferred credits and other liabilities	18,480	17,713
Total liabilities	35,318	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)	2,347	2,331
Accumulated other comprehensive loss	(97)	(76)
Retained earnings	8,476	8,328
Total Edison International's common shareholders' equity	10,726	10,583
Preferred and preference stock of utility	1,029	907
Other noncontrolling interests	2	4
Total noncontrolling interests	1,031	911
Total equity	11,757	11,494
Total liabilities and equity	$ 47,075	$ 45,530

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Commitments and Contingencies (Details 2) (USD $)			6 Months Ended	1 Months Ended	6 Months Ended			1 Months Ended	6 Months Ended	1 Months Ended	6 Months Ended	1 Months Ended	6 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2011 Edison International	Jun. 30, 2010 Southern California Edison Company	Jun. 30, 2011 Southern California Edison Company	Jun. 30, 2010 Southern California Edison Company	Jun. 30, 2011 Southern California Edison Company Nuclear Insurance	May 31, 2011 Midwest Generation LLC.	Jun. 30, 2011 Midwest Generation LLC.	Aug. 31, 2009 Midwest Generation LLC. Violation of certain operating permit requirements	Jun. 30, 2011 Midwest Generation LLC. Violation of certain operating permit requirements	Jan. 31, 2011 Homer City Violations of the PSD and Title V provisions of the CAA Pending or Threatened Litigation in January 2011	Jun. 30, 2011 SCE and other owners of San Onofre and Palo Verde Nuclear Insurance	Jun. 30, 2011 Nuclear Insurance	Jun. 30, 2011 San Onofre (nuclear)
Contingencies
Number of coal-fired electric generating stations										6
Penalties sought, per violation, per day, minimum end of range										$ 25,000		$ 32,500
Penalties sought, per violation, per day, maximum end of range										37,500		37,500
Number of fully dismissed counts in the complaint filed by the US EPA and the State of Illinois											9
Number of counts in the complaint filed by the US EPA and the State of Illinois											10
Number of complaints filed asserting claims of nuisance, negligence, trespass, and strict liability								2
Number of prior owners of facilities												2
Number of plaintiffs												2
Identified material sites for environmental remediation (in number of sites)			26		24				2
Identified material sites, minimum amount of upper end of range of costs			1,000,000
Minimum liability for environmental remediation			60,000,000		54,000,000										18,000,000
Amount that cleanup costs could exceed recorded liability for identified material sites			192,000,000
Amount that cleanup costs could exceed recorded liability for immaterial sites					7,000,000
Immaterial sites for environmental remediation (in number of sites)					33
Immaterial sites, range of liability, minimum					3,000,000
Percentage of environmental remediation costs recoverable through an incentive mechanism (as a percent)					90.00%
Portion of recorded liability recoverable from incentive mechanism					32,000,000
Environmental remediation costs to be recovered (as a percent)					100.00%
Liability incurred at majority of the remaining sites through customer rates					21,000,000
Regulatory asset, Long-term	4,690,000,000	4,347,000,000			53,000,000
Maximum expected period for cleanup of identified sites (in years)					30Y
Expected annual environmental remediation costs, low end of range					5,000,000
Expected annual environmental remediation costs, high end of range					17,000,000
Environmental remediation costs					7,000,000	3,000,000
Federal limit on public liability claims from nuclear incident, approximate														12,600,000,000
Private primary insurance purchased													375,000,000
Maximum deferred insurance premium per each nuclear incident							235,000,000
Maximum yearly assessment per nuclear incident							35,000,000
Loss limit, property damage insurance							500,000,000
Limit on assessment of retrospective premium adjustments, per year, approximate							48,000,000
Amount of damages, decision by US Court of Federal Claims, spent nuclear fuel litigation				$ 142,000,000

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Business Segments

6 Months Ended

Jun. 30, 2011

Business Segments

Business Segments

Note 17. Business Segments

Edison International has two business segments for financial reporting purposes: an electric utility operation segment (SCE) and a competitive power generation segment (EMG). The significant accounting policies of the segments are the same as those described in Note 1.

Reportable Segments Information

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

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Operating Revenue:
Electric utility	$	2,446		$	2,247		$	4,678		$	4,406
Competitive power generation		538			495			1,090			1,147
Parent and other2		(1	)		(1	)		(2	)		(1	)
Consolidated Edison International	$	2,983		$	2,741		$	5,766		$	5,552
Net Income (Loss) attributable to Edison International:
Electric utility	$	211		$	301		$	433		$	465
Competitive power generation1		(31	)		27			(51	)		104
Parent and other2		(4	)		16			(6	)		11
Consolidated Edison International	$	176		$	344		$	376		$	580

Segment balance sheet information was:

(in millions)		June 30, 2011			December 31, 2010
Total Assets:
	Electric utility	$	37,365		$	35,906
	Competitive power generation		9,804			9,597
	Parent and other2		(94	)		27
Consolidated Edison International		$	47,075		$	45,530

¹

Includes earnings (losses) from discontinued operations of $(1) million and $1 million for the three months ended June 30, 2011 and 2010, respectively, and $(3) million and $8 million for the six months ended June 30, 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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Consolidated Statements of Income (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Electric utility	$ 2,445	$ 2,246	$ 4,676	$ 4,405
Competitive power generation	538	495	1,090	1,147
Total operating revenue	2,983	2,741	5,766	5,552
Fuel	256	254	515	549
Purchased power	649	612	1,158	1,220
Operations and maintenance	1,263	1,144	2,412	2,183
Depreciation, decommissioning and amortization	435	380	852	749
Total operating expenses	2,603	2,390	4,937	4,701
Operating income	380	351	829	851
Interest and dividend income	30	4	34	23
Equity in income from unconsolidated affiliates - net	18	20	12	39
Other income	42	36	83	70
Interest expense	(203)	(175)	(398)	(343)
Other expenses	(13)	(16)	(25)	(28)
Income from continuing operations before income taxes	254	220	535	612
Income tax expense (benefit)	62	(136)	127	14
Income from continuing operations	192	356	408	598
Income (loss) from discontinued operations, net of tax	(1)	1	(3)	8
Net income	191	357	405	606
Dividends on preferred and preference stock of utility	15	13	29	26
Net income attributable to Edison International common shareholders	176	344	376	580
Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	177	343	379	572
Income (loss) from discontinued operations, net of tax	(1)	1	(3)	8
Net income attributable to Edison International common shareholders	$ 176	$ 344	$ 376	$ 580
Basic earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding (in shares)	326	326	326	326
Continuing operations (in dollars per share)	$ 0.54	$ 1.05	$ 1.16	$ 1.75
Discontinued operations (in dollars per share)			$ (0.01)	$ 0.02
Total (in dollars per share)	$ 0.54	$ 1.05	$ 1.15	$ 1.77
Diluted earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities (in shares)	329	327	328	327
Continuing operations (in dollars per share)	$ 0.54	$ 1.05	$ 1.16	$ 1.75
Discontinued operations (in dollars per share)			$ (0.01)	$ 0.02
Total (in dollars per share)	$ 0.54	$ 1.05	$ 1.15	$ 1.77
Dividends declared per common share (in dollars per share)	$ 0.320	$ 0.315	$ 0.640	$ 0.630

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Derivative Instruments and Hedging Activities (Details 3) (USD $) In Millions, unless otherwise specified			6 Months Ended	12 Months Ended	6 Months Ended		12 Months Ended	6 Months Ended	12 Months Ended	3 Months Ended		6 Months Ended			3 Months Ended	6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2011 Amortizing interest rate swap Competitive power generation Cash flow hedges Derivative Contracts Expiring on June, 2016	Dec. 31, 2010 Amortizing interest rate swap Competitive power generation Cash flow hedges Derivative Contracts Expiring on June, 2016	Jun. 30, 2011 Amortizing interest rate swap Competitive power generation Cash flow hedges Derivative Contracts Expiring on December, 2020	Jun. 30, 2011 Amortizing forward starting interest rate swap Competitive power generation Cash flow hedges Derivative Contracts Expiring on December, 2025	Dec. 31, 2010 Amortizing forward starting interest rate swap Competitive power generation Cash flow hedges Derivative Contracts Expiring on December, 2025	Jun. 30, 2011 Amortizing forward starting interest rate swap Competitive power generation Cash flow hedges Derivative Contracts Expiring on March, 2026	Dec. 31, 2010 Amortizing forward starting interest rate swap Competitive power generation Cash flow hedges Derivative Contracts Expiring on March, 2026	Jun. 30, 2011 Southern California Edison Company Electric Utility Economic hedges	Jun. 30, 2010 Southern California Edison Company Electric Utility Economic hedges	Jun. 30, 2011 Southern California Edison Company Electric Utility Economic hedges	Jun. 30, 2010 Southern California Edison Company Electric Utility Economic hedges	Dec. 31, 2010 Southern California Edison Company Electric Utility Economic hedges	Jun. 30, 2010 Edison Mission Group Inc. Competitive power generation Cash flow hedges Competitive power generation revenues	Jun. 30, 2011 Edison Mission Group Inc. Competitive power generation Cash flow hedges Competitive power generation revenues	Jun. 30, 2010 Edison Mission Group Inc. Competitive power generation Cash flow hedges Competitive power generation revenues	Jun. 30, 2011 Competitive power generation Economic hedges Competitive power generation revenues	Jun. 30, 2010 Competitive power generation Economic hedges Competitive power generation revenues	Jun. 30, 2011 Competitive power generation Economic hedges Competitive power generation revenues	Jun. 30, 2010 Competitive power generation Economic hedges Competitive power generation revenues	Jun. 30, 2011 Competitive power generation Economic hedges Fuel	Jun. 30, 2010 Competitive power generation Economic hedges Fuel	Jun. 30, 2011 Competitive power generation Economic hedges Fuel	Jun. 30, 2010 Competitive power generation Economic hedges Fuel	Jun. 30, 2011 Competitive power generation Trading activities Operating revenues	Jun. 30, 2010 Competitive power generation Trading activities Operating revenues	Jun. 30, 2011 Competitive power generation Trading activities Operating revenues	Jun. 30, 2010 Competitive power generation Trading activities Operating revenues	Jun. 30, 2011 Cash flow hedges Competitive power generation revenues	Jun. 30, 2010 Cash flow hedges Competitive power generation revenues
Derivatives
Realized loss on economic hedging activities										$ (35)	$ (38)	$ (74)	$ (62)
Notional amount of derivatives			84	138	110	120	122	67	68
Unrealized gain (loss) on economic hedging activities										(227)	(276)	(323)	(857)
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Beginning of period derivative gains																														27	175
Effective portion of changes in fair value																														(13)	30
Reclassification to net income																														(29)	(122)
End of period derivative gains (losses)																														(15)	83
Unrealized derivative gains after taxes recorded in accumulated other comprehensive income																														(9)	50
Aggregate fair value of all derivative liabilities with credit-risk-related contingent features										164		164		67
Collateral already posted, fair value														4
Additional collateral, aggregate fair value										12		12
Floating interest rate received			6-month LIBOR	6-month LIBOR	6-month LIBOR	3-month LIBOR	3-month LIBOR	3-month LIBOR	3-month LIBOR
Fixed interest rate paid (as a percent)			3.175%	3.175%	3.415%	4.29%	4.29%	3.46%	3.46%
Amount of cash flow hedge ineffectiveness															(7)	2	1
Gain (loss) on derivative instruments																		20	(3)	26	(7)	(2)	(2)	4	(1)	41	33	57	80
Collateral provided to counterparties:
Offset against derivative liabilities	4	8
Reflected in margin and collateral deposits	64	65
Collateral received from counterparties:
Offset against derivative assets	$ 33	$ 52

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Consolidated Statements of Changes in Equity (Tables)

6 Months Ended

Jun. 30, 2011

Consolidated Statements of Changes in Equity

Changes in equity

The following table provides the changes in equity for the six months ended June 30, 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		—		—			376			376			—			29			405
Other comprehensive loss		—		(21	)		—			(21	)		—			—			(21	)
Common stock dividends declared ($0.64 per share)		—		—			(209	)		(209	)		—			—			(209	)
Dividends, distributions to noncontrolling interests and other		—		—			—			—			(2	)		(29	)		(31	)
Stock-based compensation and other		4		—			(17	)		(13	)		—			—			(13	)
Noncash stock-based compensation and other		12		—			(2	)		10			—			(1	)		9
Issuance of preference stock		—		—			—			—			—			123			123
Balance at June 30, 2011	$	2,347	$	(97	)	$	8,476		$	10,726		$	2		$	1,029		$	11,757

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

	Equity Attributable to Edison International											Noncontrolling Interests
(in millions)	Common Stock		Accumulated Other Comprehensive Income			Retained Earnings			Subtotal			Other			Preferred and Preference Stock			Total Equity
Balance at December 31, 2009	$	2,304	$	37		$	7,500		$	9,841		$	258		$	907		$	11,006
Net income		—		—			580			580			—			26			606
Other comprehensive loss		—		(49	)		—			(49	)		—			—			(49	)
Deconsolidation of variable interest entities		—		—			—			—			(249	)		—			(249	)
Cumulative effect of a change in accounting principle, net of tax		—		—			15			15			—			—			15
Common stock dividends declared ($0.63 per share)		—		—			(205	)		(205	)		—			—			(205	)
Dividends, distributions to noncontrolling interests and other		—		—			—			—			(3	)		(26	)		(29	)
Stock-based compensation and other		2		—			(4	)		(2	)		—			—			(2	)
Noncash stock-based compensation and other		9		—			(7	)		2			—			—			2
Balance at June 30, 2010	$	2,315	$	(12	)	$	7,879		$	10,182		$	6		$	907		$	11,095

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Derivative Instruments and Hedging Activities (Details 2)	Jun. 30, 2011	Dec. 31, 2010
Electric Utility | Economic hedges | Electricity options, swaps and forwards in gigawatts per hour (GWh)
Derivatives
Notional Volumes of Derivative Instruments	34,471	32,138
Electric Utility | Economic hedges | Natural gas options, swaps and forwards, Bcf
Derivatives
Notional Volumes of Derivative Instruments	255	250
Electric Utility | Economic hedges | CRRs
Derivatives
Notional Volumes of Derivative Instruments	147,992	181,291
Electric Utility | Economic hedges | Tolling arrangements (GWh)
Derivatives
Notional Volumes of Derivative Instruments	105,631	114,599
Competitive power generation | Cash flow hedges | Electricity Forwards/Futures, Sales, GWh
Derivatives
Notional Volumes of Derivative Instruments	18,901	16,799
Competitive power generation | Cash flow hedges | Electricity Forwards/Futures, Purchases, GWh
Derivatives
Notional Volumes of Derivative Instruments	203	408
Competitive power generation | Cash flow hedges | Electricity Capacity, Sales, MW-Day (in thousands)
Derivatives
Notional Volumes of Derivative Instruments	171,000	190,000
Competitive power generation | Cash flow hedges | Electricity Capacity, Purchases, MW-Day (in thousands)
Derivatives
Notional Volumes of Derivative Instruments	17,000	8,000
Competitive power generation | Economic hedges | Electricity Forwards/Futures, Sales, GWh
Derivatives
Notional Volumes of Derivative Instruments	17,660	22,456
Competitive power generation | Economic hedges | Electricity Forwards/Futures, Purchases, GWh
Derivatives
Notional Volumes of Derivative Instruments	17,750	22,931
Competitive power generation | Economic hedges | Electricity Congestion, Sales, GWh
Derivatives
Notional Volumes of Derivative Instruments	124	136
Competitive power generation | Economic hedges | Electricity Congestion, Purchases, GWh
Derivatives
Notional Volumes of Derivative Instruments	5,459	1,143
Competitive power generation | Economic hedges | Natural Gas Forwards/Futures, Sales, billion cubic feet
Derivatives
Notional Volumes of Derivative Instruments	1.5
Competitive power generation | Economic hedges | Natural Gas Forwards/Futures, Purchases, billion cubic feet
Derivatives
Notional Volumes of Derivative Instruments	1.5
Competitive power generation | Economic hedges | Fuel Oil Forwards/Futures, Sales, Barrels
Derivatives
Notional Volumes of Derivative Instruments		250,000
Competitive power generation | Economic hedges | Fuel Oil Forwards/Futures, Purchases, Barrels
Derivatives
Notional Volumes of Derivative Instruments	240,000	490,000
Competitive power generation | Trading activities | Electricity Forwards/Futures, Sales, GWh
Derivatives
Notional Volumes of Derivative Instruments	39,629	34,630
Competitive power generation | Trading activities | Electricity Forwards/Futures, Purchases, GWh
Derivatives
Notional Volumes of Derivative Instruments	42,863	37,669
Competitive power generation | Trading activities | Electricity Capacity, Sales, MW-Day (in thousands)
Derivatives
Notional Volumes of Derivative Instruments	17,000	136,000
Competitive power generation | Trading activities | Electricity Capacity, Purchases, MW-Day (in thousands)
Derivatives
Notional Volumes of Derivative Instruments	247,000	419,000
Competitive power generation | Trading activities | Electricity Congestion, Sales, GWh
Derivatives
Notional Volumes of Derivative Instruments	14,314	12,020
Competitive power generation | Trading activities | Electricity Congestion, Purchases, GWh
Derivatives
Notional Volumes of Derivative Instruments	287,221	187,689
Competitive power generation | Trading activities | Natural Gas Forwards/Futures, Sales, billion cubic feet
Derivatives
Notional Volumes of Derivative Instruments	354.1	30.6
Competitive power generation | Trading activities | Natural Gas Forwards/Futures, Purchases, billion cubic feet
Derivatives
Notional Volumes of Derivative Instruments	351.8	34.3
Competitive power generation | Trading activities | Fuel Oil Forwards/Futures, Sales, Barrels
Derivatives
Notional Volumes of Derivative Instruments	45,000	10,000
Competitive power generation | Trading activities | Fuel Oil Forwards/Futures, Purchases, Barrels
Derivatives
Notional Volumes of Derivative Instruments	70,000	10,000
Competitive power generation | Trading activities | Coal Forwards/Futures, Sales, tons
Derivatives
Notional Volumes of Derivative Instruments	2,564,250	2,630,500
Competitive power generation | Trading activities | Coal Forwards/Futures, Purchases, tons
Derivatives
Notional Volumes of Derivative Instruments	2,564,250	2,645,500

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Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

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 options, swaps, forwards, tolling arrangements and CRRs. These transactions are pre-approved by the California Public Utilities Commission ("CPUC") or executed in compliance with CPUC-approved procurement plans. SCE recovers its related hedging costs through the energy resource recovery account ("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 and sold to the California and other wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities, power purchase agreements and California Department of Water Resources ("CDWR") contracts allocated to SCE.

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	June 30, 2011		December 31, 2010
Electricity options, swaps and forwards	GWh		34,471		32,138
Natural gas options, swaps and forwards	Bcf		255		250
CRRs	GWh		147,992		181,291
Tolling arrangements	GWh		105,631		114,599

Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at June 30, 2011:

	Derivative Assets									Derivative Liabilities
(in millions)	Short- Term			Long- Term			Subtotal			Short- Term			Long- Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	89		$	200		$	289		$	243		$	579		$	822		$	533
Netting and collateral		(11	)		(21	)		(32	)		(12	)		(21	)		(33	)		(1	)
Total	$	78		$	179		$	257		$	231		$	558		$	789		$	532

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.

The following table summarizes the components of economic hedging activity:

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Realized losses	$	(35	)	$	(38	)	$	(74	)	$	(62	)
Unrealized losses		(227	)		(276	)		(323	)		(857	)

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 $164 million and $67 million as of June 30, 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 June 30, 2011, SCE would be required to post $12 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. 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 its 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 EMG's consolidated balance sheets with offsetting changes recorded on the consolidated statements of operations. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized, to the extent effective, on EMG's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive loss until the related forecasted 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 operations.

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 its consolidated balance sheets.

Notional Volumes of Derivative Instruments

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

June 30, 2011
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges			Economic Hedges			Trading Activities
Electricity	Forwards/Futures	Sales	GWh		18,901	1		17,660	3		39,629
Electricity	Forwards/Futures	Purchases	GWh		203	1		17,750	3		42,863
Electricity	Capacity	Sales	MW-Day (in thousands)		171	2		—			17	2
Electricity	Capacity	Purchases	MW-Day (in thousands)		17	2		—			247	2
Electricity	Congestion	Sales	GWh		—			124	4		14,314	4
Electricity	Congestion	Purchases	GWh		—			5,459	4		287,221	4
Natural gas	Forwards/Futures	Sales	bcf		—			1.5			354.1
Natural gas	Forwards/Futures	Purchases	bcf		—			1.5			351.8
Fuel oil	Forwards/Futures	Sales	barrels		—			—			45,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			240,000			70,000
Coal	Forwards/Futures	Sales	tons		—			—			2,564,250
Coal	Forwards/Futures	Purchases	tons		—			—			2,564,250

(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	$	84	June 2016
Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.415%) debt	Cash flow		110	December 2020
Amortizing interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt	Cash flow		120	December 2025
Amortizing interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt	Cash flow		67	March 2026

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:

June 30, 2011
		Derivative Assets									Derivative Liabilities
																				Net Assets (Liabilities)
(in millions)		Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal
Non-trading activities
	Cash flow hedges	$	27		$	2		$	29		$	14		$	34		$	48		$	(19	)
	Economic hedges		60			4			64			51			1			52			12
Trading activities			141			88			229			98			20			118			111
			228			94			322			163			55			218			104
Netting and collateral received1			(189	)		(31	)		(220	)		(157	)		(32	)		(189	)		(31	)
Total		$	39		$	63		$	102		$	6		$	23		$	29		$	73

December 31, 2010
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 received1			(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 cash flow hedge activity as part of accumulated other comprehensive loss:

	Cash Flow Hedge Activity1 Six Months Ended June 30,
							Income Statement Location
(in millions)	2011			2010
Beginning of period derivative gains	$	27		$	175
Effective portion of changes in fair value		(13	)		30
Reclassification to net income		(29	)		(122	)	Competitive power generation revenue
End of period derivative gains (losses)	$	(15	)	$	83

¹

Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income (loss) at June 30, 2011 and 2010 were $(9) million and $50 million, respectively.

For additional information, see Note 11—Accumulated Other Comprehensive Loss.

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 (losses) of none and $(7) million during the second quarters of 2011 and 2010, respectively, and $2 million and $1 million during the six months ended June 30, 2011 and 2010, respectively, in operating revenues on the consolidated statements of operations 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 operations is presented below:

		Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	Income Statement Location	2011			2010			2011		2010
Economic hedges	Competitive power generation revenue	$	20		$	(3	)	$	26	$	(7	)
	Fuel		(2	)		(2	)		4		(1	)
Trading activities	Competitive power generation revenue		41			33			57		80

Contingent Features

Certain derivative instruments contain margin and collateral deposit requirements. Since EMG's subsidiaries' credit ratings are below investment grade, EMG's subsidiaries have 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 June 30, 2011 and, accordingly, the contingent features described below do not currently have liquidity exposure. 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. Edison Mission Marketing & Trading, Inc. ("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's subsidiaries to termination payments or additional collateral postings.

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)		June 30, 2011		December 31, 2010
Collateral provided to counterparties:
	Offset against derivative liabilities	$	4	$	8
	Reflected in margin and collateral deposits		64		65
Collateral received from counterparties:
	Offset against derivative assets		33		52

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Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2011

Variable Interest Entities

Summarized financial information of the consolidated projects

(in millions)		June 30, 2011		December 31, 2010
Current assets		$	39	$	26
Net property, plant and equipment			712		739
Other long-term assets			5		6
	Total assets	$	756	$	771
Current liabilities		$	23	$	25
Long-term debt net of current portion			68		71
Deferred revenues			69		71
Other long-term liabilities			21		21
	Total liabilities	$	181	$	188
Noncontrolling interests		$	3	$	4

Carrying amount of investments in unconsolidated variable interest entities and the maximum exposure to loss for each investment

	June 30, 2011
(in millions)	Investment		Maximum Exposure
Natural gas-fired projects	$	321	$	321
Renewable energy projects		229		229

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Liabilities at Fair Value
Percentage of equity investments located in the United States (as a percent)	68.00%		68.00%		67.00%
Collateralized mortgage obligations and other asset backed securities			$ 27		$ 27
Receivables (payables) net related to investments	11		11		(5)
Cash surrender value of life insurance	31		31		31
Total realized/unrealized gains (losses):
Unrealized gain loss related to Level 3 financial instruments reported within competitive power generation revenue	14	(2)	8	32
Level 1
Assets at Fair Value
Money market funds	743		743		1,100
Long-term disability plan	9		9		9
Nuclear decommissioning trusts	2,375		2,375		2,245
Total assets	3,133		3,133		3,363
Liabilities at Fair Value
Net assets (liabilities)	3,133		3,133		3,363
Level 1 | Stocks
Assets at Fair Value
Nuclear decommissioning trusts	2,062		2,062		2,029
Level 1 | U.S. government and agency securities
Assets at Fair Value
Nuclear decommissioning trusts	309		309		215
Level 1 | Short-term investments, primarily cash equivalents
Assets at Fair Value
Nuclear decommissioning trusts	4		4		1
Level 1 | Commodity contracts.
Assets at Fair Value
Derivative contracts	6		6		9
Level 1 | Natural gas
Assets at Fair Value
Derivative contracts					1
Level 1 | Fuel oil
Assets at Fair Value
Derivative contracts	6		6		8
Level 2
Assets at Fair Value
Nuclear decommissioning trusts	1,271		1,271		1,240
Total assets	1,381		1,381		1,379
Liabilities at Fair Value
Total liabilities	270		270		316
Net assets (liabilities)	1,111		1,111		1,063
Level 2 | Municipal bonds
Assets at Fair Value
Nuclear decommissioning trusts	812		812		790
Level 2 | U.S. government and agency securities
Assets at Fair Value
Nuclear decommissioning trusts	118		118		73
Level 2 | Corporate bonds
Assets at Fair Value
Nuclear decommissioning trusts	310		310		346
Level 2 | Short-term investments, primarily cash equivalents
Assets at Fair Value
Nuclear decommissioning trusts	31		31		31
Level 2 | Commodity contracts.
Assets at Fair Value
Derivative contracts	110		110		139
Liabilities at Fair Value
Derivative contracts	248		248		300
Level 2 | Electricity
Assets at Fair Value
Derivative contracts	44		44		70
Liabilities at Fair Value
Derivative contracts	9		9		13
Level 2 | Natural gas
Assets at Fair Value
Derivative contracts	65		65		69
Liabilities at Fair Value
Derivative contracts	239		239		286
Level 2 | Coal
Assets at Fair Value
Derivative contracts	1		1
Liabilities at Fair Value
Derivative contracts					1
Level 2 | Interest rate contracts.
Liabilities at Fair Value
Derivative contracts	22		22		16
Level 3
Assets at Fair Value
Total assets	283		283		492
Liabilities at Fair Value
Total liabilities	558		558		395
Net assets (liabilities)	(275)		(275)		97
Fair Value Disclosures Level 3
Fair value, net asset (liabilities) at beginning of period	(44)	(397)	97	62	62
Total realized/unrealized gains (losses):
Included in earnings	18	(18)	18	27
Included in regulatory assets and liabilities	(247)	(294)	(382)	(781)
Included in accumulated other comprehensive income	(4)	(2)	(3)	4
Purchases	22	26	28	32
Settlements	(20)	(24)	(31)	(52)
Transfers in or out of Level 3		6	(2)	5
Fair value, net liability at end of period	(275)	(703)	(275)	(703)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period	(226)	(287)	(368)	(717)
Level 3 | Commodity contracts.
Assets at Fair Value
Derivative contracts	283		283		492
Liabilities at Fair Value
Derivative contracts	558		558		395
Level 3 | Electricity
Assets at Fair Value
Derivative contracts	231		231		363
Liabilities at Fair Value
Derivative contracts	71		71		40
Level 3 | Natural gas
Assets at Fair Value
Derivative contracts	11		11		11
Liabilities at Fair Value
Derivative contracts	6		6		11
Level 3 | Tolling
Assets at Fair Value
Derivative contracts	41		41		118
Liabilities at Fair Value
Derivative contracts	481		481		344
Netting and Collateral
Assets at Fair Value
Total assets	(40)		(40)		(70)
Liabilities at Fair Value
Total liabilities	(10)		(10)		(26)
Net assets (liabilities)	(30)		(30)		(44)
Netting and Collateral | Commodity contracts.
Assets at Fair Value
Derivative contracts	(40)		(40)		(70)
Liabilities at Fair Value
Derivative contracts	(10)		(10)		(26)
Netting and Collateral | Electricity
Assets at Fair Value
Derivative contracts	(33)		(33)		(61)
Liabilities at Fair Value
Derivative contracts	(9)		(9)		(21)
Netting and Collateral | Natural gas
Assets at Fair Value
Derivative contracts					(1)
Liabilities at Fair Value
Derivative contracts	(1)		(1)		(4)
Netting and Collateral | Fuel oil
Assets at Fair Value
Derivative contracts	(6)		(6)		(8)
Netting and Collateral | Coal
Assets at Fair Value
Derivative contracts	(1)		(1)
Liabilities at Fair Value
Derivative contracts					(1)
Total
Assets at Fair Value
Money market funds	743		743		1,100
Long-term disability plan	9		9		9
Nuclear decommissioning trusts	3,646		3,646		3,485
Total assets	4,757		4,757		5,164
Liabilities at Fair Value
Total liabilities	818		818		685
Net assets (liabilities)	3,939		3,939		4,479
Total | Stocks
Assets at Fair Value
Nuclear decommissioning trusts	2,062		2,062		2,029
Total | Municipal bonds
Assets at Fair Value
Nuclear decommissioning trusts	812		812		790
Total | U.S. government and agency securities
Assets at Fair Value
Nuclear decommissioning trusts	427		427		288
Total | Corporate bonds
Assets at Fair Value
Nuclear decommissioning trusts	310		310		346
Total | Short-term investments, primarily cash equivalents
Assets at Fair Value
Nuclear decommissioning trusts	35		35		32
Total | Commodity contracts.
Assets at Fair Value
Derivative contracts	359		359		570
Liabilities at Fair Value
Derivative contracts	796		796		669
Total | Electricity
Assets at Fair Value
Derivative contracts	242		242		372
Liabilities at Fair Value
Derivative contracts	71		71		32
Total | Natural gas
Assets at Fair Value
Derivative contracts	76		76		80
Liabilities at Fair Value
Derivative contracts	244		244		293
Total | Tolling
Assets at Fair Value
Derivative contracts	41		41		118
Liabilities at Fair Value
Derivative contracts	481		481		344
Total | Interest rate contracts.
Liabilities at Fair Value
Derivative contracts	$ 22		$ 22		$ 16

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Summary of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Summary of Significant Accounting Policies
Segment Reporting, Number of Segments	2
Cash Equivalents
Money market funds	$ 743	$ 1,100
Maximum maturity period of cash equivalent investments (in months)	3
Cash reclassified to accounts payable under cash management program	185	197
Inventory
Coal, gas, fuel oil and other raw materials	203	184
Spare parts, materials and supplies	386	384
Total inventory	$ 589	$ 568

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2011

Summary of Significant Accounting Policies

Inventory Components

(in millions)	June 30, 2011		December 31, 2010
Coal, gas, fuel oil and other raw materials	$	203	$	184
Spare parts, materials and supplies		386		384
Total inventory	$	589	$	568

EPS computation

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

	Three months ended June 30,					Six months ended June 30,
(in millions)	2011		2010			2011		2010
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	177	$	343		$	379	$	572
Participating securities dividends		—		(2	)		—		(2	)
Income from continuing operations available to common shareholders	$	177	$	341		$	379	$	570
Weighted average common shares outstanding		326		326			326		326
Basic earnings per share – continuing operations	$	0.54	$	1.05		$	1.16	$	1.75
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	177	$	341		$	379	$	570
Income impact of assumed conversions		1		1			1		1
Income from continuing operations available to common shareholders and assumed conversions	$	178	$	342		$	380	$	571
Weighted average common shares outstanding		326		326			326		326
Incremental shares from assumed conversions		3		1			2		1
Adjusted weighted average shares – diluted		329		327			328		327
Diluted earnings per share – continuing operations	$	0.54	$	1.05		$	1.16	$	1.75

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Accumulated Other Comprehensive Loss

6 Months Ended

Jun. 30, 2011

Accumulated Other Comprehensive Loss.

Accumulated Other Comprehensive Loss

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		(25	)		4			—			(21	)
Balance at June 30, 2011	$	(9	)	$	(83	)	$	(5	)	$	(97	)

Included in accumulated other comprehensive loss at June 30, 2011 was $4 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $13 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 $8 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy 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.

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Consolidated Statements of Changes in Equity

6 Months Ended

Jun. 30, 2011

Consolidated Statements of Changes in Equity

Consolidated Statements of Changes in Equity

Note 2. Consolidated Statements of Changes in Equity

The following table provides the changes in equity for the six months ended June 30, 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		—		—			376			376			—			29			405
Other comprehensive loss		—		(21	)		—			(21	)		—			—			(21	)
Common stock dividends declared ($0.64 per share)		—		—			(209	)		(209	)		—			—			(209	)
Dividends, distributions to noncontrolling interests and other		—		—			—			—			(2	)		(29	)		(31	)
Stock-based compensation and other		4		—			(17	)		(13	)		—			—			(13	)
Noncash stock-based compensation and other		12		—			(2	)		10			—			(1	)		9
Issuance of preference stock		—		—			—			—			—			123			123
Balance at June 30, 2011	$	2,347	$	(97	)	$	8,476		$	10,726		$	2		$	1,029		$	11,757

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

	Equity Attributable to Edison International											Noncontrolling Interests
(in millions)	Common Stock		Accumulated Other Comprehensive Income			Retained Earnings			Subtotal			Other			Preferred and Preference Stock			Total Equity
Balance at December 31, 2009	$	2,304	$	37		$	7,500		$	9,841		$	258		$	907		$	11,006
Net income		—		—			580			580			—			26			606
Other comprehensive loss		—		(49	)		—			(49	)		—			—			(49	)
Deconsolidation of variable interest entities		—		—			—			—			(249	)		—			(249	)
Cumulative effect of a change in accounting principle, net of tax		—		—			15			15			—			—			15
Common stock dividends declared ($0.63 per share)		—		—			(205	)		(205	)		—			—			(205	)
Dividends, distributions to noncontrolling interests and other		—		—			—			—			(3	)		(26	)		(29	)
Stock-based compensation and other		2		—			(4	)		(2	)		—			—			(2	)
Noncash stock-based compensation and other		9		—			(7	)		2			—			—			2
Balance at June 30, 2010	$	2,315	$	(12	)	$	7,879		$	10,182		$	6		$	907		$	11,095

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Other Investments (Tables)

6 Months Ended

Jun. 30, 2011

Other Investments

Amortized cost and fair value of the trust investments:

		Amortized Cost				Fair Value
(in millions)	Longest Maturity Dates	June 30, 2011		December 31, 2010		June 30, 2011		December 31, 2010
Stocks	—	$	862	$	895	$	2,062	$	2,029
Municipal bonds	2050		699		706		812		790
U.S. government and agency securities	2041		396		270		427		288
Corporate bonds	2054		255		288		310		346
Short-term investments and receivables/payables	One-year		44		26		46		27
Total		$	2,256	$	2,185	$	3,657	$	3,480

Summary of changes in the fair value of trust

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Balance at beginning of period	$	3,619		$	3,248		$	3,480		$	3,140
Realized gains – net		12			13			35			34
Unrealized gains (losses) – net		4			(205	)		106			(143	)
Other-than-temporary impairments		(4	)		(7	)		(13	)		(11	)
Interest, dividends, contributions and other		26			34			49			63
Balance at end of period	$	3,657		$	3,083		$	3,657		$	3,083

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Compensation and Benefit Plans

6 Months Ended

Jun. 30, 2011

Compensation and Benefit Plans

Compensation and Benefit Plans

Note 8. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

During the six months ended June 30, 2011, Edison International made contributions of $61 million and during the remainder of 2011, expects to make $69 million of additional contributions. 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 June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Service cost	$	43		$	34		$	86		$	68
Interest cost		52			54			104			108
Expected return on plan assets		(60	)		(52	)		(120	)		(104	)
Amortization of prior service cost		2			2			4			4
Amortization of net loss		6			7			12			14
Expense under accounting standards		43			45			86			90
Regulatory adjustment – deferred		(6	)		(14	)		(12	)		(28	)
Total expense recognized	$	37		$	31		$	74		$	62

Postretirement Benefits Other Than Pensions

During the six months ended June 30, 2011, Edison International made contributions of $12 million and during the remainder of 2011, expects to make $44 million of additional contributions. Annual contributions made to SCE's 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 June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Service cost	$	11		$	8		$	22		$	16
Interest cost		33			31			66			62
Expected return on plan assets		(28	)		(25	)		(56	)		(50	)
Amortization of prior service cost (credit)		(9	)		(9	)		(18	)		(18	)
Amortization of net loss		9			8			18			16
Total expense	$	16		$	13		$	32		$	26

Stock-Based Compensation

During the six months ended June 30, 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		3,314,149			37.95
Expired		(87,641	)		47.93
Forfeited		(244,066	)		32.52
Exercised		(1,002,771	)		24.74
Outstanding at June 30, 2011		21,121,880			34.37		6.26
Vested and expected to vest at June 30, 2011		20,639,870			34.38		6.21	$	136
Exercisable at June 30, 2011		12,613,025			34.70		4.74		93

At June 30, 2011, there was $28 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					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		148,697			27.96		148,697
Forfeited		(113,762	)		43.42		(113,762	)
Nonvested at June 30, 2011		449,963			28.04		449,963			29.43

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.

At June 30, 2011, there was $6 million 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:

	Restricted Stock Units			Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2010		644,796		$	32.18
Granted		247,408			37.95
Forfeited		(16,467	)		32.13
Paid Out		(104,420	)		52.35
Nonvested at June 30, 2011		771,317		$	31.98

At June 30, 2011, there was $12 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $4 million in 2011, $5 million in 2012 and $3 million in 2013.

Supplemental Data on Stock Based Compensation

		Three months ended June 30,				Six months ended June 30,
(in millions)		2011		2010		2011		2010
Stock based compensation expense1		$	11	$	9	$	17	$	17
Income tax benefits related to stock compensation expense			5		4		7		7
Excess tax benefits2			2		1		4		2
Stock options
	Cash used to purchase shares to settle options		20		6		39		13
	Cash from participants to exercise stock options		12		4		25		9
	Value of options exercised		8		2		14		4
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 for both the six month periods ended June 30, 2011 and 2010.

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Preferred and Preference Stock of Utility

6 Months Ended

Jun. 30, 2011

Preferred and Preference Stock of Utility

Preferred and Preference Stock of Utility

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 for a price of $100 per share plus accrued and unpaid dividends, if any. These shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used for general corporate purposes.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Commitments and Contingencies.

Commitments and Contingencies

Note 9. Commitments and Contingencies

Third-Party Power Purchase Agreements

At June 30, 2011, additional renewable energy power purchase contracts became effective and were classified as operating leases. SCE's additional commitments under these contracts are estimated to be: $6 million in 2011, $116 million each year in 2012 – 2015 and $1.9 billion for the period remaining thereafter.

Other Commitments

Fuel Supply Contracts

At June 30, 2011, Midwest Generation and EME Homer City Generation L.P. ("Homer City") had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses. These commitments are estimated to aggregate $634 million, summarized as follows: $277 million for the remainder of 2011, $304 million in 2012 and $53 million in 2013. In July 2011, Midwest Generation entered into additional contractual agreements for the purchase of coal. These commitments are estimated to be $6 million for the remainder of 2011, $28 million for 2012, $145 million for 2013 and $150 million for 2014.

Turbine Commitments

At June 30, 2011, EMG had commitments to purchase wind turbines of $45 million due in 2011 and $8 million due in 2012. Based on a June 2011 contract amendment, EMG's failure to schedule turbine delivery by September 2011 would result in a termination obligation equal to its turbine deposit, which would result in a $29 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.

Capital Expenditures

At June 30, 2011, EMG's subsidiaries had firm commitments to spend approximately $242 million during the remainder of 2011, $205 million in 2012 and $19 million in 2013 on capital and construction expenditures. These expenditures primarily relate to the Walnut Creek project, selective non-catalytic reduction (SNCR) equipment at the Midwest Generation plants, and the construction of wind projects. EMG intends to fund these expenditures through project level financing, U.S. Treasury grants, Midwest Generation and EME lines of credit, if available, cash on hand and cash generated from operations.

Guarantees and Indemnities

Edison International's subsidiaries have various financial and performance guarantees and indemnity agreements which are issued in the normal course of business. The contracts discussed below included performance guarantees.

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 obligations are reduced by any insurance proceeds and tax benefits related to such indemnified claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. 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. These indemnities are not limited in term or amount. 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 and Other Litigation." 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 Midwest Generation's 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. 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 222 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at June 30, 2011. Midwest Generation had recorded a liability of $55 million at June 30, 2011 related to this contractual 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. 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. EME has not recorded a liability related to this indemnity. For discussion of the New Source Review lawsuit filed against Homer City, see "—Contingencies—Homer City New Source Review and Other Litigation."

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. At June 30, 2011, EME had recorded a liability of $45 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). Not all indemnities under the asset sale agreements have specific expiration dates. Due to the nature of these potential obligations, a maximum potential liability cannot be determined and has not been recorded as a liability related to these indemnities.

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. EME has not recorded a liability for these matters.

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 indemnities for specified environmental liabilities and income taxes with respect to assets sold. Edison International's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances Edison International may have recourse against third parties. Edison International has not recorded a liability related to these indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.

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 and Other Litigation

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 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") emission 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 emission 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.

Nine of ten PSD claims have been dismissed, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court has 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.

In May 2011, two complaints were filed against Midwest Generation in the Northern District of Illinois by residents living near the Crawford and Fisk facilities on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs seek to have their suits certified as a class action and request injunctive relief, as well as compensatory and punitive damages.

Adverse decisions in these cases could involve penalties and remedial actions that could have a material 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 and Other Litigation

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, 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 emission 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 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, as well as compensatory and punitive damages.

In April 2011, Homer City filed motions to dismiss both complaints. Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material 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

On August 1, 2011, SCE and the other defendants entered into a comprehensive settlement with the Navajo Nation of the litigation filed in June 1999 against SCE and others concerning royalty payments to the Navajo for the coal supplied to the Mohave Generating Station. As amended in April 2010, the Navajo Nation's complaint asserted claims for, among other things, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The settlement will result in a payment to the Navajo Nation and other related parties. As a result of the settlement, the Navajo Nation lawsuit will be dismissed. The settlement agreement reached with the Navajo Nation will not impact SCE's results of operations.

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 single 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 June 30, 2011, Edison International's recorded estimated minimum liability to remediate its 26 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 (2 sites primarily related to Midwest Generation) was $60 million, of which $54 million was related to SCE, including $18 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. 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 $192 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 $32 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). In addition, SCE expects to recover 100% of environmental remediation costs incurred at the majority of the remaining sites through customer rates, representing $21 million of its recorded liability. SCE has recorded a regulatory asset of $53 million at June 30, 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 $5 million to $17 million. Costs incurred for the six months ended June 30, 2011 and 2010, were $7 million and $3 million, respectively.

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 estimates.

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 June 2010, the United States Court of Federal Claims issued a decision granting SCE and its co-owners damages of approximately $142 million to recover costs incurred through December 31, 2005 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. The decision 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.

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Accumulated Other Comprehensive Loss (Tables)

6 Months Ended

Jun. 30, 2011

Accumulated Other Comprehensive Loss.

Components of accumulated other comprehensive loss

(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		(25	)		4			—			(21	)
Balance at June 30, 2011	$	(9	)	$	(83	)	$	(5	)	$	(97	)

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Income Taxes

6 Months Ended

Jun. 30, 2011

Income Taxes

Income Taxes

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 June 30,						Six months ended June 30,
(in millions)			2011			2010			2011			2010
Income from continuing operations before income taxes			$	254		$	220		$	535		$	612
Provision for income tax at federal statutory rate of 35%				89			77			187			214
Increase (decrease) in income tax from:
	Items presented with related state income tax, net:
		Global Settlement related1		—			(138	)		—			(138	)
		Change in tax accounting method for asset removal costs2		—			(40	)		—			(40	)
	State tax – net of federal benefit			4			16			13			23
	Health care legislation3			—			—			—			39
	Production and housing credits			(19	)		(19	)		(36	)		(34	)
	Property-related and other			(12	)		(32	)		(37	)		(50	)
Total income tax expense from continuing operations			$	62		$	(136	)	$	127		$	14
Effective tax rate				24%			(62%	)		24%			2%

¹

During the second quarter of 2010, Edison International recognized a $138 million earnings benefit resulting from the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service ("IRS") in 2009 as part of the Global Settlement.

²

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

³

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 decreased benefit provided by property-related and other items was primarily due to lower deductions for internally developed software in 2011 compared to the respective periods in 2010.

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 upon examination. 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		26			35
Tax positions taken during a prior year:
	Increases		14			127
	Decreases		(10	)		(40	)
	Decreases for settlements during the period		—			(82	)
Balance at June 30,		$	595		$	704

As of June 30, 2011 and December 31, 2010, $468 million and $455 million, respectively, of the unrecognized tax benefits, if recognized, would impact the effective tax rate.

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 $189 million, including interest and penalties through June 30, 2011 (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 $91 million, including interest through June 30, 2011.

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 $222 million and $213 million as of June 30, 2011 and December 31, 2010, respectively.

The net after-tax interest and penalties recognized in income tax expense was $2 million and $5 million for the three- and six-month periods ended June 30, 2011, respectively, compared to a benefit of $101 million and $88 million for the same periods in 2010.

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Commitments and Contingencies (Details) (USD $)			6 Months Ended	1 Months Ended			6 Months Ended	1 Months Ended
	Jun. 30, 2011 Southern California Edison Company Environmental Indemnities	Jun. 30, 2011 Southern California Edison Company Operating Leases - Purchase Power Contracts	Jun. 30, 2011 Edison Mission Group Inc. Turbine commitments	Oct. 31, 2010 Edison Mission Group Inc. Mitsubishi Power Systems Americans, Inc. and Mitsubishi Heavy Industries, Ltd. mW	Jun. 30, 2011 Edison Mission Group Inc. Capital Expenditures	Jun. 30, 2011 Edison Mission Energy Indemnities under International Asset Sale Agreements	Jun. 30, 2011 Midwest Generation and EME Homer City Generation L.P. (Homer City) Purchase of fuel and transportation of gas and coal	Jul. 31, 2011 Midwest Generation LLC. Purchase of fuel and transportation of gas and coal	Feb. 28, 2003 Midwest Generation LLC. Environmental Indemnities under Acquisition Agreement	Jun. 30, 2011 Midwest Generation LLC. Environmental Indemnities under Acquisition Agreement
Third-Party Power Purchase Agreements
Estimated additional commitments in 2011		$ 6,000,000
Estimated additional commitments in 2012		116,000,000
Estimated additional commitments in 2013		116,000,000
Estimated additional commitments in 2014		116,000,000
Estimated additional commitments in 2015		116,000,000
Estimated additional commitments for the period remaining thereafter		1,900,000,000
Other Commitments
Purchase commitments, remainder of 2011							277,000,000	6,000,000
Purchase commitments, 2012							304,000,000	28,000,000
Purchase commitments, 2013							53,000,000	145,000,000
Purchase commitments, 2014								150,000,000
Purchase commitments, aggregate							634,000,000
Turbine Commitments
Commitments to purchase turbines in 2011			45,000,000
Commitments to purchase turbines in 2012			8,000,000
Charges for default of termination of turbine commitments			29,000,000
Additional wind turbines to be deployed in future				60
Additional power generating capacity of turbines to be deployed in future (in megawatts)				144
Payment obligation to be made following the end of three year period from date of settlement agreement				30,000,000
Period after which payment may be due (in years)				3
Capital Expenditures
Wind turbine payment commitments in remainder of 2011					242,000,000
Wind turbine payment commitments in 2012					205,000,000
Wind turbine payment commitments in 2013					19,000,000
Guarantees and Indemnities
Percentage reimbursement obligation for asbestos claims (as a percent)									50.00%
Term of asbestos supplemental agreement									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.
Number of cases not settled and dismissed creating potential liability										222
Liability under indemnities						45,000,000				55,000,000
Maximum liability under indemnity per Mountainview purchase agreement for damages and other amounts	$ 60,000,000

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Consolidated Statements of Cash Flows (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Cash flows from operating activities:
Net income	$ 405	$ 606
Less: Income (loss) from discontinued operations	(3)	8
Income from continuing operations	408	598
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	852	749
Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)	75	74
Other amortization	75	56
Stock-based compensation	15	14
Equity in income from unconsolidated affiliates - net	(12)	(39)
Distributions from unconsolidated entities	15	39
Deferred income taxes and investment tax credits	223	247
Proceeds from U.S. treasury grants		92
Income from leveraged leases	(3)	(2)
Changes in operating assets and liabilities:
Receivables	64	13
Inventory	(21)	(36)
Margin and collateral deposits - net of collateral received	1	12
Prepaid taxes	34	(167)
Other current assets	(189)	(136)
Rent payments in excess of levelized rent expense	(101)	(111)
Accounts payable	66	(114)
Accrued taxes	(19)	(69)
Other current liabilities	(212)	(164)
Derivative assets and liabilities - net	303	806
Regulatory assets and liabilities - net	(260)	(720)
Other assets	(31)	(36)
Other liabilities	(58)	(152)
Operating cash flows from discontinued operations	(3)	8
Net cash provided by operating activities	1,222	962
Cash flows from financing activities:
Long-term debt issued	592	645
Long-term debt issuance costs	(5)	(19)
Long-term debt repaid	(30)	(366)
Bonds purchased	(56)
Preference stock issued - net	123
Short-term debt financing - net	292	410
Settlements of stock-based compensation - net	(13)	(2)
Dividends and distributions to noncontrolling interests	(28)	(25)
Dividends paid	(209)	(205)
Net cash provided by financing activities	666	438
Cash flows from investing activities:
Capital expenditures	(2,256)	(2,070)
Purchase of interest in acquired companies		(4)
Proceeds from sale of nuclear decommissioning trust investments	1,146	600
Purchases of nuclear decommissioning trust investments and other	(1,230)	(697)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment	5	44
Investments in other assets	3	13
Effect of consolidation and deconsolidation of variable interest entities		(91)
Net cash used by investing activities	(2,332)	(2,205)
Net decrease in cash and cash equivalents	(444)	(805)
Cash and cash equivalents, beginning of period	1,389	1,673
Cash and cash equivalents, end of period	$ 945	$ 868

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Variable Interest Entities

6 Months Ended

Jun. 30, 2011

Variable Interest Entities

Variable Interest Entities

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. 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 June 30, 2011 and December 31, 2010, EMG consolidated 13 and 14 projects, respectively, with a total generating capacity of 570 MW and 580 MW, respectively, that have interests held by others. In April 2011, EMG sold its 75% ownership interest in a Minnesota wind project.

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

(in millions)		June 30, 2011		December 31, 2010
Current assets		$	39	$	26
Net property, plant and equipment			712		739
Other long-term assets			5		6
	Total assets	$	756	$	771
Current liabilities		$	23	$	25
Long-term debt net of current portion			68		71
Deferred revenues			69		71
Other long-term liabilities			21		21
	Total liabilities	$	181	$	188
Noncontrolling interests		$	3	$	4

At June 30, 2011 and December 31, 2010, assets serving as collateral for the debt obligations had a carrying value of $163 million 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 have variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to operate the plants and 10 contracts with qualifying facilities ("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. 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. As a result, 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 June 30, 2011 and the amounts that SCE paid to these projects were $83 million and $117 million for the three months ended June 30, 2011 and 2010, respectively, and $169 million and $242 million for the six months ended June 30, 2011 and 2010, respectively. These amounts are recovered in customer rates.

Equity Interests

EMG accounts for domestic gas and wind energy projects in which it has less than a 100% ownership interest, and cannot exercise unilateral control, under the equity method. At June 30, 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 the Sunrise project and EMG's partner provides the fuel management services for the Big 4 projects. 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 accounts for its variable interests under the equity method.

At June 30, 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. In addition, EMG accounts for its interests in Community Wind North, which achieved commercial operation on May 28, 2011, under the equity method. The commercial and operating activities of these entities are jointly directed by representatives of each partner. Thus, EMG is not the primary beneficiary of these projects.

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

	June 30, 2011
(in millions)	Investment		Maximum Exposure
Natural gas-fired projects	$	321	$	321
Renewable energy projects		229		229

EMG's maximum exposure to loss in its VIEs accounted for under the equity method is generally limited to its investment in these entities. One of EMG's domestic energy projects has long-term debt that is secured by a pledge of project entity assets, but does not provide for recourse to EMG. Accordingly, a default under the project financing could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EMG's investment, but would not require EMG to contribute additional capital. At June 30, 2011, entities which EMG has accounted for under the equity method had indebtedness of $65 million, of which $16 million is proportionate to EMG's ownership interest in this project.

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Consolidated Statements of Changes in Equity (Details) (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			$ 11,494	$ 11,006
Net income	191	357	405	606
Other comprehensive (loss)	(20)	(128)	(21)	(49)
Deconsolidation of variable interest entities				(249)
Cumulative effect of a change in accounting principle, net of tax				15
Common stock dividends declared ($0.64 and $0.63 per share for the period ended March 31, 2011 and March 31, 2010 respectively)			(209)	(205)
Dividends, distributions to noncontrolling interests and other			(31)	(29)
Stock-based compensation and other			(13)	(2)
Noncash stock-based compensation and other			9	2
Issuance of preference stock			123
Balance, at the end of period	11,757	11,095	11,757	11,095
Common stock dividends declared (in dollars per share)	$ 0.320	$ 0.315	$ 0.640	$ 0.630
Equity Attributable to Edison International
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			10,583	9,841
Net income			376	580
Other comprehensive (loss)			(21)	(49)
Cumulative effect of a change in accounting principle, net of tax				15
Common stock dividends declared ($0.64 and $0.63 per share for the period ended March 31, 2011 and March 31, 2010 respectively)			(209)	(205)
Stock-based compensation and other			(13)	(2)
Noncash stock-based compensation and other			10	2
Balance, at the end of period	10,726	10,182	10,726	10,182
Common Stock
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			2,331	2,304
Stock-based compensation and other			4	2
Noncash stock-based compensation and other			12	9
Balance, at the end of period	2,347	2,315	2,347	2,315
Accumulated Other Comprehensive Loss
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			(76)	37
Other comprehensive (loss)			(21)	(49)
Balance, at the end of period	(97)	(12)	(97)	(12)
Retained Earnings
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			8,328	7,500
Net income			376	580
Cumulative effect of a change in accounting principle, net of tax				15
Common stock dividends declared ($0.64 and $0.63 per share for the period ended March 31, 2011 and March 31, 2010 respectively)			(209)	(205)
Stock-based compensation and other			(17)	(4)
Noncash stock-based compensation and other			(2)	(7)
Balance, at the end of period	8,476	7,879	8,476	7,879
Other
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			4	258
Deconsolidation of variable interest entities				(249)
Dividends, distributions to noncontrolling interests and other			(2)	(3)
Balance, at the end of period	2	6	2	6
Preferred and Preference Stock
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			907	907
Net income			29	26
Dividends, distributions to noncontrolling interests and other			(29)	(26)
Noncash stock-based compensation and other			(1)
Issuance of preference stock			123
Balance, at the end of period	$ 1,029	$ 907	$ 1,029	$ 907

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Compensation and Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2011

Compensation and Benefit Plans

Expense components for pension plan

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Service cost	$	43		$	34		$	86		$	68
Interest cost		52			54			104			108
Expected return on plan assets		(60	)		(52	)		(120	)		(104	)
Amortization of prior service cost		2			2			4			4
Amortization of net loss		6			7			12			14
Expense under accounting standards		43			45			86			90
Regulatory adjustment – deferred		(6	)		(14	)		(12	)		(28	)
Total expense recognized	$	37		$	31		$	74		$	62

Expense components for postretirement benefits other than pension

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Service cost	$	11		$	8		$	22		$	16
Interest cost		33			31			66			62
Expected return on plan assets		(28	)		(25	)		(56	)		(50	)
Amortization of prior service cost (credit)		(9	)		(9	)		(18	)		(18	)
Amortization of net loss		9			8			18			16
Total expense	$	16		$	13		$	32		$	26

Summary of the status of 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		3,314,149			37.95
Expired		(87,641	)		47.93
Forfeited		(244,066	)		32.52
Exercised		(1,002,771	)		24.74
Outstanding at June 30, 2011		21,121,880			34.37		6.26
Vested and expected to vest at June 30, 2011		20,639,870			34.38		6.21	$	136
Exercisable at June 30, 2011		12,613,025			34.70		4.74		93

Summary of nonvested performance shares

	Equity Awards					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		148,697			27.96		148,697
Forfeited		(113,762	)		43.42		(113,762	)
Nonvested at June 30, 2011		449,963			28.04		449,963			29.43

Summary of nonvested restricted stock units

	Restricted Stock Units			Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2010		644,796		$	32.18
Granted		247,408			37.95
Forfeited		(16,467	)		32.13
Paid Out		(104,420	)		52.35
Nonvested at June 30, 2011		771,317		$	31.98

Schedule of Supplemental Data on Stock Based Compensation

		Three months ended June 30,				Six months ended June 30,
(in millions)		2011		2010		2011		2010
Stock based compensation expense1		$	11	$	9	$	17	$	17
Income tax benefits related to stock compensation expense			5		4		7		7
Excess tax benefits2			2		1		4		2
Stock options
	Cash used to purchase shares to settle options		20		6		39		13
	Cash from participants to exercise stock options		12		4		25		9
	Value of options exercised		8		2		14		4
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.

XML



Regulatory Assets and Liabilities (Details) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Regulatory Assets
Regulatory Assets, Current	$ 469	$ 378
Regulatory asset, Long-term	4,690	4,347
Total Regulatory Assets	5,159	4,725
Regulatory Liabilities
Regulatory Liabilities, Current	820	738
Regulatory Liabilities, Long-term	4,759	4,524
Total Regulatory Liabilities	5,579	5,262
Regulatory balancing accounts, current assets
Regulatory Assets
Regulatory Assets, Current	268	213
Energy derivatives
Regulatory Assets
Regulatory Assets, Current	194	162
Regulatory asset, Long-term	465	177
Other:
Regulatory Assets
Regulatory Assets, Current	7	3
Regulatory asset, Long-term	297	280
Regulatory Liabilities
Regulatory Liabilities, Current	2	5
Deferred income taxes - net
Regulatory Assets
Regulatory asset, Long-term	1,912	1,855
Pensions and other postretirement benefits
Regulatory Assets
Regulatory asset, Long-term	1,089	1,097
Unamortized generation investment - net
Regulatory Assets
Regulatory asset, Long-term	328	355
Unamortized loss on reacquired debt
Regulatory Assets
Regulatory asset, Long-term	258	268
Nuclear-related ARO investment - net
Regulatory Assets
Regulatory asset, Long-term	163	154
Unamortized distribution investment - net
Regulatory Assets
Regulatory asset, Long-term	125	105
Regulatory balancing accounts, noncurrent assets
Regulatory Assets
Regulatory asset, Long-term	53	56
Costs of removal
Regulatory Liabilities
Regulatory Liabilities, Long-term	2,663	2,623
ARO
Regulatory Liabilities
Regulatory Liabilities, Long-term	1,250	1,099
Regulatory balancing accounts, liabilities
Regulatory Liabilities
Regulatory Liabilities, Current	818	733
Regulatory Liabilities, Long-term	$ 846	$ 802

XML



Other Income and Expenses (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Other income:
Equity AFUDC	$ 27	$ 25	$ 56	$ 54
Increase in cash surrender value of life insurance policies	7	6	13	12
Other	5	4	8	4
Total utility other income	39	35	77	70
Competitive power generation and other income	3	1	6
Total other income	42	36	83	70
Other expenses:
Civic, political and related activities and donations	9	9	15	15
Other	4	6	10	11
Total utility other expenses	13	15	25	26
Competitive power generation and other expenses		1		2
Total other expenses	$ 13	$ 16	$ 25	$ 28

XML



Compensation and Benefit Plans (Details 2) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Stock Options
Outstanding, at the beginning of period (in options)			19,142,209
Granted (in options)			3,314,149
Expired (in options)			(87,641)
Forfeited (in options)			(244,066)
Exercised (in options)			(1,002,771)
Outstanding, at the end of period (in options)	21,121,880		21,121,880
Vested and expected to vest, at the end of period (in options)	20,639,870		20,639,870
Exercisable, at the end of period (in options)	12,613,025		12,613,025
Weighted-Average Exercise Price
Outstanding, at the beginning of period (in dollars per option)			$ 33.28
Granted (in dollars per option)	$ 37.95		$ 37.95
Expired (in dollars per option)	$ 47.93		$ 47.93
Forfeited (in dollars per option)	$ 32.52		$ 32.52
Exercised (in dollars per option)	$ 24.74		$ 24.74
Outstanding, at the end of period (in dollars per option)	$ 34.37		$ 34.37
Vested and expected to vest, at the end of period (in dollars per option)	$ 34.38		$ 34.38
Exercisable, at the end of period (in dollars per option)	$ 34.70		$ 34.70
Weighted-Average Remaining Contractual Term (Years)
Outstanding, at the end of period (in years)			6.26
Vested and expected to vest, at the end of period (in years)			6.21
Exercisable, at the end of period (in years)			4.74
Aggregate Intrinsic Value
Vested and expected to vest, at the end of period	$ 136		$ 136
Exercisable, at the end of period			93
Supplemental Data on Stock Based Compensation
Stock Based Compensation Expense	11	9	17	17
Income tax benefits related to stock compensation expense	5	4	7	7
Excess tax benefits	2	1	4	2
Cash used to purchase shares to settle options	20	6	39	13
Cash from participants to exercise stock options	12	4	25	9
Value of options exercised	8	2	14	4
Value of shares settled			5
Tax benefits realized from settlement of awards			2
Performance Shares
Weighted-Average Fair Value
Total unrecognized compensation cost	6		6
Weighted-average period, recognition of unrecognized compensation cost (in years)			2
Performance shares classified as equity awards
Performance Shares
Nonvested, at the beginning of the period (in shares)			415,028
Granted (in shares)			148,697
Forfeited (in shares)			(113,762)
Nonvested, at the end of the period (in shares)	449,963		449,963
Weighted-Average Fair Value
Nonvested, at the beginning of the period (in dollars per share)			$ 30.99
Granted (in dollars per share)			$ 27.96
Forfeited (in dollars per share)	$ 43.42		$ 43.42
Nonvested, at the end of the period (in dollars per share)	$ 28.04		$ 28.04
Performance shares classified as liability awards
Performance Shares
Nonvested, at the beginning of the period (in shares)			415,028
Granted (in shares)			148,697
Forfeited (in shares)			(113,762)
Nonvested, at the end of the period (in shares)	449,963		449,963
Weighted-Average Fair Value
Nonvested, at the beginning of the period (in dollars per share)			$ 34.74
Nonvested, at the end of the period (in dollars per share)	$ 29.43		$ 29.43
Restricted Stock Units
Performance Shares
Nonvested, at the beginning of the period (in shares)			644,796
Granted (in shares)			247,408
Forfeited (in shares)			(16,467)
Paid out (in shares)			(104,420)
Nonvested, at the end of the period (in shares)	771,317		771,317
Weighted-Average Fair Value
Nonvested, at the beginning of the period (in dollars per share)			$ 32.18
Granted (in dollars per share)			$ 37.95
Forfeited (in dollars per share)	$ 32.13		$ 32.13
Paid out (in dollars per share)			$ 52.35
Nonvested, at the end of the period (in dollars per share)	$ 31.98		$ 31.98
Total unrecognized compensation cost	12		12
Compensation cost to be recognized in 2011	4		4
Compensation cost to be recognized in 2012	5		5
Compensation cost to be recognized in 2013	3		3
Stock Options
Weighted-Average Fair Value
Total unrecognized compensation cost	$ 28		$ 28
Weighted-average period, recognition of unrecognized compensation cost (in years)			3

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Fair Value Measurements

6 Months Ended

Jun. 30, 2011

Fair Value Measurements

Fair Value Measurements

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).

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

		As of June 30, 2011
(in millions)		Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2		$	743	$	—	$	—		$	—		$	743
Derivative contracts:
	Electricity		—		44		231			(33	)		242
	Natural gas		—		65		11			—			76
	Fuel oil		6		—		—			(6	)		—
	Tolling		—		—		41			—			41
	Coal		—		1		—			(1	)		—
Subtotal of commodity contracts			6		110		283			(40	)		359
Long-term disability plan			9		—		—			—			9
Nuclear decommissioning trusts:
	Stocks3		2,062		—		—			—			2,062
	Municipal bonds		—		812		—			—			812
	U.S. government and agency securities		309		118		—			—			427
	Corporate bonds4		—		310		—			—			310
	Short-term investments, primarily cash equivalents5		4		31		—			—			35
Subtotal of nuclear decommissioning trusts			2,375		1,271		—			—			3,646
Total assets6			3,133		1,381		283			(40	)		4,757
Liabilities at Fair Value
Derivative contracts:
	Electricity		—		9		71			(9	)		71
	Natural gas		—		239		6			(1	)		244
	Tolling		—		—		481			—			481
Subtotal of commodity contracts			—		248		558			(10	)		796
Interest rate contracts			—		22		—			—			22
Total liabilities			—		270		558			(10	)		818
Net assets (liabilities)		$	3,133	$	1,111	$	(275	)	$	(30	)	$	3,939

		As of December 31, 2010
(in millions)		Level 1		Level 2		Level 3		Netting and Collateral1			Total
Assets at Fair Value
Money market funds2		$	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:
	Stocks3		2,029		—		—		—			2,029
	Municipal bonds		—		790		—		—			790
	Corporate bonds4		—		346		—		—			346
	U.S. government and agency securities		215		73		—		—			288
	Short-term investments, primarily cash equivalents5		1		31		—		—			32
Subtotal of nuclear decommissioning trusts			2,245		1,240		—		—			3,485
Total assets6			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 June 30, 2011 and December 31, 2010, respectively.

⁴

Corporate bonds are diversified, and included $27 million at both June 30, 2011 and December 31, 2010, respectively, for collateralized mortgage obligations and other asset backed securities.

⁵

Excludes net receivables of $11 million and net liabilities of $5 million at June 30, 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 June 30, 2011 and December 31, 2010, respectively, of cash surrender value of life insurance investments for deferred compensation.

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

		Three months ended June 30,						Six months ended June 30,
(in millions)		2011			2010			2011			2010
Fair value, net asset (liabilities) at beginning of period		$	(44	)	$	(397	)	$	97		$	62
Total realized/unrealized gains (losses):
	Included in earnings1		18			(18	)		18			27
	Included in regulatory assets and liabilities2		(247	)		(294	)		(382	)		(781	)
	Included in accumulated other comprehensive income		(4	)		(2	)		(3	)		4
Purchases			22			26			28			32
Settlements			(20	)		(24	)		(31	)		(52	)
Transfers in or out of Level 3			—			6			(2	)		5
Fair value, net liability at end of period		$	(275	)	$	(703	)	$	(275	)	$	(703	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period3		$	(226	)	$	(287	)	$	(368	)	$	(717	)

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 $14 million and $(2) million for the three months ended June 30, 2011 and 2010, respectively, and were $8 million and $32 million for the six months ended June 30, 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 financial 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.

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), 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 June 30, 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:

	June 30, 2011				December 31, 2010
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	13,009	$	13,075	$	12,419	$	12,360

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.

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Variable Interest Entities (Details 2) (USD $) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Variable Interest Entity, Not Primary Beneficiary
Details of projects or entities
Number of projects operated by the subsidiary	three of the four Big 4 projects
Variable Interest Entity, Not Primary Beneficiary | EMG Domestic Energy Projects
Details of projects or entities
Projects having secured long-term debt to finance the assets constructed and/or acquired by entity	1
Indebtedness of projects accounted for under equity method	65
Indebtedness of projects accounted for under equity method, amount proportionate to ownership interest	16
Variable Interest Entity, Not Primary Beneficiary Holds Significant interest | EMG Domestic Energy Projects
Details of projects or entities
Equity Interest in Domestic Energy Projects (as a percent)	100.00%
EMG Wind Projects | Variable Interest Entity, Deconsolidated
Details of projects or entities
Interests in number of wind projects	2	2
Variable Interest Entity, Deconsolidated | EMG Domestic Energy Projects
Details of projects or entities
Number of projects	5	5
EMG Natural Gas-Fired Projects
Details of projects or entities
Investment	321
Maximum Exposure, Total	321
EMG Renewable energy projects
Details of projects or entities
Investment	229
Maximum Exposure, Total	229

XML



Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2011

Fair Value Measurements

Fair value by level

		As of June 30, 2011
(in millions)		Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2		$	743	$	—	$	—		$	—		$	743
Derivative contracts:
	Electricity		—		44		231			(33	)		242
	Natural gas		—		65		11			—			76
	Fuel oil		6		—		—			(6	)		—
	Tolling		—		—		41			—			41
	Coal		—		1		—			(1	)		—
Subtotal of commodity contracts			6		110		283			(40	)		359
Long-term disability plan			9		—		—			—			9
Nuclear decommissioning trusts:
	Stocks3		2,062		—		—			—			2,062
	Municipal bonds		—		812		—			—			812
	U.S. government and agency securities		309		118		—			—			427
	Corporate bonds4		—		310		—			—			310
	Short-term investments, primarily cash equivalents5		4		31		—			—			35
Subtotal of nuclear decommissioning trusts			2,375		1,271		—			—			3,646
Total assets6			3,133		1,381		283			(40	)		4,757
Liabilities at Fair Value
Derivative contracts:
	Electricity		—		9		71			(9	)		71
	Natural gas		—		239		6			(1	)		244
	Tolling		—		—		481			—			481
Subtotal of commodity contracts			—		248		558			(10	)		796
Interest rate contracts			—		22		—			—			22
Total liabilities			—		270		558			(10	)		818
Net assets (liabilities)		$	3,133	$	1,111	$	(275	)	$	(30	)	$	3,939

		As of December 31, 2010
(in millions)		Level 1		Level 2		Level 3		Netting and Collateral1			Total
Assets at Fair Value
Money market funds2		$	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:
	Stocks3		2,029		—		—		—			2,029
	Municipal bonds		—		790		—		—			790
	Corporate bonds4		—		346		—		—			346
	U.S. government and agency securities		215		73		—		—			288
	Short-term investments, primarily cash equivalents5		1		31		—		—			32
Subtotal of nuclear decommissioning trusts			2,245		1,240		—		—			3,485
Total assets6			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 June 30, 2011 and December 31, 2010, respectively.

⁴

Corporate bonds are diversified, and included $27 million at both June 30, 2011 and December 31, 2010, respectively, for collateralized mortgage obligations and other asset backed securities.

⁵

Excludes net receivables of $11 million and net liabilities of $5 million at June 30, 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 June 30, 2011 and December 31, 2010, respectively, of cash surrender value of life insurance investments for deferred compensation.

Summary of changes in the fair value of Level 3 financial instruments

		Three months ended June 30,						Six months ended June 30,
(in millions)		2011			2010			2011			2010
Fair value, net asset (liabilities) at beginning of period		$	(44	)	$	(397	)	$	97		$	62
Total realized/unrealized gains (losses):
	Included in earnings1		18			(18	)		18			27
	Included in regulatory assets and liabilities2		(247	)		(294	)		(382	)		(781	)
	Included in accumulated other comprehensive income		(4	)		(2	)		(3	)		4
Purchases			22			26			28			32
Settlements			(20	)		(24	)		(31	)		(52	)
Transfers in or out of Level 3			—			6			(2	)		5
Fair value, net liability at end of period		$	(275	)	$	(703	)	$	(275	)	$	(703	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period3		$	(226	)	$	(287	)	$	(368	)	$	(717	)

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 $14 million and $(2) million for the three months ended June 30, 2011 and 2010, respectively, and were $8 million and $32 million for the six months ended June 30, 2011 and 2010, respectively. The remainder of the unrealized losses relate to SCE. See 2 above.

Carrying amounts and fair values of long-term debt

	June 30, 2011				December 31, 2010
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	13,009	$	13,075	$	12,419	$	12,360

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Business Segments (Details 2) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Reportable Segments Information
Operating Revenue:	$ 2,983	$ 2,741	$ 5,766	$ 5,552
Net Income (Loss) attributable to Edison International:	176	344	376	580
Total Assets:	47,075		47,075		45,530
Income (loss) from discontinued operations, net of tax	(1)	1	(3)	8
Electric Utility
Reportable Segments Information
Operating Revenue:	2,446	2,247	4,678	4,406
Net Income (Loss) attributable to Edison International:	211	301	433	465
Total Assets:	37,365		37,365		35,906
Competitive power generation
Reportable Segments Information
Operating Revenue:	538	495	1,090	1,147
Net Income (Loss) attributable to Edison International:	(31)	27	(51)	104
Total Assets:	9,804		9,804		9,597
Income (loss) from discontinued operations, net of tax	(1)	1	(3)	8
Parent and other
Reportable Segments Information
Operating Revenue:	(1)	(1)	(2)	(1)
Net Income (Loss) attributable to Edison International:	(4)	16	(6)	11
Total Assets:	$ (94)		$ (94)		$ 27

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Supplemental Cash Flows Information (Tables)

6 Months Ended

Jun. 30, 2011

Supplemental Cash Flows Information

Supplemental Cash Flows Information

			Six months ended June 30,
(in millions)			2011			2010
Cash payments (receipts) for interest and taxes:
	Interest – net of amounts capitalized		$	321		$	305
	Tax payments (refunds) – net			(44	)		179
Noncash investing and financing activities:
	Accrued capital expenditures		$	388		$	333
	Purchase of equipment with note payable		$	56		$	—
	Details of debt exchange:
		Pollution-control bonds redeemed	$	(56	)	$	(203	)
		Pollution-control bonds issued		56			203
	Consolidation of variable interest entities:
		Assets other than cash	$	—		$	(94	)
		Liabilities and non-controlling interests		—			99
	Deconsolidation of variable interest entities:
		Assets other than cash	$	—		$	380
		Liabilities and noncontrolling interests		—			(476	)
	Dividends declared but not paid:
		Common stock	$	104		$	103
		Preferred and preference stock		15			13

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Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified			1 Months Ended					3 Months Ended		6 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	Apr. 30, 2011 EMG Wind Projects Variable Interest Entity, Primary Beneficiary	Jun. 30, 2011 EMG Wind Projects Variable Interest Entity, Primary Beneficiary mW	Dec. 31, 2010 EMG Wind Projects Variable Interest Entity, Primary Beneficiary mW	Jun. 30, 2011 Variable Interest Entity, Primary Beneficiary	Dec. 31, 2010 Variable Interest Entity, Primary Beneficiary	Jun. 30, 2011 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts mW	Jun. 30, 2010 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts	Jun. 30, 2011 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts mW	Jun. 30, 2010 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts
Details of projects or entities
Number of projects				13	14			16		16
Power generating capacity for majority interest (in megawatts)				570	580			3,820		3,820
Sale of ownership interest (as a percent)			75.00%
Number of projects consolidated				13	14
Summarized balance sheet information of VIEs
Current assets	$ 4,337	$ 4,422				$ 39	$ 26
Net property, plant and equipment	5,613	5,406				712	739
Other long-term assets	591	644				5	6
Total assets	47,075	45,530				756	771
Current liabilities	3,882	3,952				23	25
Long-term debt net of current portion	12,956	12,371				68	71
Deferred revenues						69	71
Other long-term liabilities	2,147	2,041				21	21
Total liabilities	35,318	34,036				181	188
Noncontrolling interests	1,031	911				3	4
Assets serving as collateral for the debt obligations						163	163
Power Purchase Agreement With Tolling Agreement								6		6
Power Purchase Agreement With Qualified Facilities								10		10
Payments to unconsolidated VIEs, power purchase contracts								$ 83	$ 117	$ 169	$ 242

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2011

Income Taxes

Reconciliation of Income Tax Expense

			Three months ended June 30,						Six months ended June 30,
(in millions)			2011			2010			2011			2010
Income from continuing operations before income taxes			$	254		$	220		$	535		$	612
Provision for income tax at federal statutory rate of 35%				89			77			187			214
Increase (decrease) in income tax from:
	Items presented with related state income tax, net:
		Global Settlement related1		—			(138	)		—			(138	)
		Change in tax accounting method for asset removal costs2		—			(40	)		—			(40	)
	State tax – net of federal benefit			4			16			13			23
	Health care legislation3			—			—			—			39
	Production and housing credits			(19	)		(19	)		(36	)		(34	)
	Property-related and other			(12	)		(32	)		(37	)		(50	)
Total income tax expense from continuing operations			$	62		$	(136	)	$	127		$	14
Effective tax rate				24%			(62%	)		24%			2%

¹

During the second quarter of 2010, Edison International recognized a $138 million earnings benefit resulting from the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service ("IRS") in 2009 as part of the Global Settlement.

²

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

³

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.

Reconciliation of Unrecognized Tax Benefits

(in millions)		2011			2010
Balance at January 1,		$	565		$	664
Tax positions taken during the current year:
	Increases		26			35
Tax positions taken during a prior year:
	Increases		14			127
	Decreases		(10	)		(40	)
	Decreases for settlements during the period		—			(82	)
Balance at June 30,		$	595		$	704

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Supplemental Cash Flows Information

6 Months Ended

Jun. 30, 2011

Supplemental Cash Flows Information

Supplemental Cash Flows Information

Note 12. Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

			Six months ended June 30,
(in millions)			2011			2010
Cash payments (receipts) for interest and taxes:
	Interest – net of amounts capitalized		$	321		$	305
	Tax payments (refunds) – net			(44	)		179
Noncash investing and financing activities:
	Accrued capital expenditures		$	388		$	333
	Purchase of equipment with note payable		$	56		$	—
	Details of debt exchange:
		Pollution-control bonds redeemed	$	(56	)	$	(203	)
		Pollution-control bonds issued		56			203
	Consolidation of variable interest entities:
		Assets other than cash	$	—		$	(94	)
		Liabilities and non-controlling interests		—			99
	Deconsolidation of variable interest entities:
		Assets other than cash	$	—		$	380
		Liabilities and noncontrolling interests		—			(476	)
	Dividends declared but not paid:
		Common stock	$	104		$	103
		Preferred and preference stock		15			13

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Supplemental Cash Flows Information (Details) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Cash payments (receipts) for interest and taxes:
Interest - net of amounts capitalized	$ 321	$ 305
Tax payments (refunds)- net	(44)	179
Noncash investing and financing activities:
Accrued capital expenditures	388	333
Purchase of equipment with note payable	56
Details of debt exchange:
Pollution-control bonds redeemed	(56)	(203)
Pollution-control bonds issued	56	203
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	$ 15	$ 13

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Business Segments (Details)	6 Months Ended
	Jun. 30, 2011
Business Segments
Segment Reporting, Number of Segments	2

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Debt and Credit Agreements

6 Months Ended

Jun. 30, 2011

Debt and Credit Agreements

Debt and Credit Agreements

Note 5. Debt and Credit Agreements

Long-Term Debt

In May 2011, SCE issued $500 million of 3.875% first and refunding mortgage bonds due in 2021. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.

In May 2011, SCE purchased $56 million of its tax-exempt bonds that were subject to remarketing and also converted these bonds to a variable rate structure. These bonds are held by SCE and remain outstanding and have not been retired or cancelled.

Project Financings

Walnut Creek

On July 27, 2011, EMG completed, through wholly owned subsidiaries, non-recourse financings to fund construction of the Walnut Creek project, a 479 MW natural gas-fired peaker plant in southern California. The financings included $122 million of letter of credit and working capital facilities, and also included floating rate construction loans totaling $495 million (with initial fundings of $48 million) that will convert to 10-year amortizing term loans by June 30, 2013, subject to meeting specified conditions.

As of July 27, 2011, EME entered into interest rate swap agreements and forward-starting interest rate swap agreements that converted the floating rate London Interbank Offered Rate ("LIBOR") construction loans to fixed rates. Under the interest rate swap agreements, EME will pay fixed rates of an average of 0.81% through May 31, 2013. Under the forward-starting swaps agreements, EME will pay an average fixed rate of 3.59% beginning June 30, 2013 through May 31, 2023. Interest under the project-level construction term loan of $442 million initially accrues at LIBOR plus 2.25% and increases by 0.25% after the third, sixth and ninth anniversaries. Interest on the intermediate holding company construction term loan of $53 million accrues at LIBOR plus 4.00% over the term.

Viento Funding II Wind Financing Amendment

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 June 30, 2011, $216 million was outstanding under this loan. The amount of outstanding letters of credit was $23 million. Interest under the term loan accrues at LIBOR plus 2.75% initially with the rate increasing 0.25% on every fourth anniversary.

Credit Agreements and Short-Term Debt

At June 30, 2011, SCE's outstanding short-term debt was $200 million at a weighted-average interest rate of 0.33%. 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 June 30, 2011, letters of credit issued under SCE's credit facilities aggregated $71 million and are scheduled to expire in twelve months or less.

At June 30, 2011, Edison International (Parent)'s outstanding short-term debt was $79 million at a weighted-average interest rate of 0.55%. 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 June 30, 2011, standby letters of credit under EME's credit facility aggregated $116 million and were scheduled to expire as follows: $39 million in 2011 and $77 million in 2012. The aggregate amount includes $39 million of letters of credit issued for the benefit of SCE, which is the power purchase agreement counterparty for the Walnut Creek project. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $51 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 $18 million in 2018. Certain letters of credit are subject to automatic annual renewal provisions.

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Other Investments

6 Months Ended

Jun. 30, 2011

Other Investments

Other Investments

Note 15. Other Investments

Nuclear Decommissioning Trusts

Future 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	June 30, 2011		December 31, 2010		June 30, 2011		December 31, 2010
Stocks	—	$	862	$	895	$	2,062	$	2,029
Municipal bonds	2050		699		706		812		790
U.S. government and agency securities	2041		396		270		427		288
Corporate bonds	2054		255		288		310		346
Short-term investments and receivables/payables	One-year		44		26		46		27
Total		$	2,256	$	2,185	$	3,657	$	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 $524 million and $315 million for the three months ended June 30, 2011 and 2010, respectively, and $1.1 billion and $600 million for the six months ended June 30, 2011 and 2010, respectively. Unrealized holding gains, net of losses, were $1.4 billion and $1.3 billion at June 30, 2011 and December 31, 2010, respectively.

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

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Balance at beginning of period	$	3,619		$	3,248		$	3,480		$	3,140
Realized gains – net		12			13			35			34
Unrealized gains (losses) – net		4			(205	)		106			(143	)
Other-than-temporary impairments		(4	)		(7	)		(13	)		(11	)
Interest, dividends, contributions and other		26			34			49			63
Balance at end of period	$	3,657		$	3,083		$	3,657		$	3,083

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

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Document and Entity Information	6 Months Ended
	Jun. 30, 2011	Aug. 01, 2011
Document and Entity Information
Entity Registrant Name	EDISON INTERNATIONAL
Entity Central Index Key	0000827052
Document Type	10-Q
Document Period End Date	Jun. 30, 2011
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		325,811,206
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2

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Summary of Significant Accounting Policies (Details 2) (USD $) In Millions, except Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Basic earnings (loss) per share - continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$ 177	$ 343	$ 379	$ 572
Participating securities dividends		(2)		(2)
Income from continuing operations available to common shareholders	177	341	379	570
Weighted average common shares outstanding (in shares)	326,000,000	326,000,000	326,000,000	326,000,000
Basic earnings per share - continuing operations (in dollars per share)	$ 0.54	$ 1.05	$ 1.16	$ 1.75
Diluted earnings (loss) per share - continuing operations:
Income from continuing operations available to common shareholders	177	341	379	570
Income impact of assumed conversions	1	1	1	1
Income from continuing operations available to common shareholders and assumed conversions	$ 178	$ 342	$ 380	$ 571
Weighted-average shares of common stock outstanding (in shares)	326,000,000	326,000,000	326,000,000	326,000,000
Incremental shares from assumed conversions (in shares)	3,000,000	1,000,000	2,000,000	1,000,000
Adjusted weighted average shares - diluted (in shares)	329,000,000	327,000,000	328,000,000	327,000,000
Diluted earnings (loss) per share - continuing operations (in dollars per share)	$ 0.54	$ 1.05	$ 1.16	$ 1.75
Stock-based compensation awards
Antidilutive Securities Excluded from Computation of Earnings Per Share
Stock-based compensation awards excluded from the computation of diluted earnings per share (in shares)	5,896,940	9,645,334	5,896,940	6,080,199

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Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Hedging Activities

Notional Volumes of Derivative Instruments for Electric Utility Segment

		Economic Hedges
Commodity	Unit of Measure	June 30, 2011		December 31, 2010
Electricity options, swaps and forwards	GWh		34,471		32,138
Natural gas options, swaps and forwards	Bcf		255		250
CRRs	GWh		147,992		181,291
Tolling arrangements	GWh		105,631		114,599

Fair Value of Derivative Instruments of Electric Utility Segment

The following table summarizes the gross and net fair values of commodity derivative instruments at June 30, 2011:

	Derivative Assets									Derivative Liabilities
(in millions)	Short- Term			Long- Term			Subtotal			Short- Term			Long- Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	89		$	200		$	289		$	243		$	579		$	822		$	533
Netting and collateral		(11	)		(21	)		(32	)		(12	)		(21	)		(33	)		(1	)
Total	$	78		$	179		$	257		$	231		$	558		$	789		$	532

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

Summarization of economic hedging activities of Electric Utility

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Realized losses	$	(35	)	$	(38	)	$	(74	)	$	(62	)
Unrealized losses		(227	)		(276	)		(323	)		(857	)

Notional Volumes of Derivative Instruments for Competitive Power Generation Segment

June 30, 2011
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges			Economic Hedges			Trading Activities
Electricity	Forwards/Futures	Sales	GWh		18,901	1		17,660	3		39,629
Electricity	Forwards/Futures	Purchases	GWh		203	1		17,750	3		42,863
Electricity	Capacity	Sales	MW-Day (in thousands)		171	2		—			17	2
Electricity	Capacity	Purchases	MW-Day (in thousands)		17	2		—			247	2
Electricity	Congestion	Sales	GWh		—			124	4		14,314	4
Electricity	Congestion	Purchases	GWh		—			5,459	4		287,221	4
Natural gas	Forwards/Futures	Sales	bcf		—			1.5			354.1
Natural gas	Forwards/Futures	Purchases	bcf		—			1.5			351.8
Fuel oil	Forwards/Futures	Sales	barrels		—			—			45,000
Fuel oil	Forwards/Futures	Purchases	barrels		—			240,000			70,000
Coal	Forwards/Futures	Sales	tons		—			—			2,564,250
Coal	Forwards/Futures	Purchases	tons		—			—			2,564,250

(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	$	84	June 2016
Amortizing interest rate swap	Convert floating rate (6-month LIBOR) debt to fixed rate (3.415%) debt	Cash flow		110	December 2020
Amortizing interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt	Cash flow		120	December 2025
Amortizing interest rate swap	Convert floating rate (3-month LIBOR) debt to fixed rate (3.46%) debt	Cash flow		67	March 2026

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 of Competitive Power Generation Segment

June 30, 2011
		Derivative Assets									Derivative Liabilities
																				Net Assets (Liabilities)
(in millions)		Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal
Non-trading activities
	Cash flow hedges	$	27		$	2		$	29		$	14		$	34		$	48		$	(19	)
	Economic hedges		60			4			64			51			1			52			12
Trading activities			141			88			229			98			20			118			111
			228			94			322			163			55			218			104
Netting and collateral received1			(189	)		(31	)		(220	)		(157	)		(32	)		(189	)		(31	)
Total		$	39		$	63		$	102		$	6		$	23		$	29		$	73

December 31, 2010
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 received1			(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.

Activity of accumulated other comprehensive income for Competitive Power Generation Segment

	Cash Flow Hedge Activity1 Six Months Ended June 30,
							Income Statement Location
(in millions)	2011			2010
Beginning of period derivative gains	$	27		$	175
Effective portion of changes in fair value		(13	)		30
Reclassification to net income		(29	)		(122	)	Competitive power generation revenue
End of period derivative gains (losses)	$	(15	)	$	83

¹

Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income (loss) at June 30, 2011 and 2010 were $(9) million and $50 million, respectively.

Effect of realized and unrealized gains (losses) from derivative instruments on Competitive Power Generation Segment

		Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	Income Statement Location	2011			2010			2011		2010
Economic hedges	Competitive power generation revenue	$	20		$	(3	)	$	26	$	(7	)
	Fuel		(2	)		(2	)		4		(1	)
Trading activities	Competitive power generation revenue		41			33			57		80

Summary of margin and collateral deposits provided to and received from counterparties

(in millions)		June 30, 2011		December 31, 2010
Collateral provided to counterparties:
	Offset against derivative liabilities	$	4	$	8
	Reflected in margin and collateral deposits		64		65
Collateral received from counterparties:
	Offset against derivative assets		33		52

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data	Jun. 30, 2011	Dec. 31, 2010
Consolidated Balance Sheets
Receivables, allowances for uncollectible accounts (in dollars)	$ 87	$ 85
Utility property, plant and equipment, accumulated depreciation (in dollars)	6,486	6,319
Competitive power generation and other property, plant and equipment, accumulated depreciation (in dollars)	$ 2,009	$ 1,865
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares issued	325,811,206	325,811,206
Common stock, shares outstanding	325,811,206	325,811,206

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Other Income and Expenses

6 Months Ended

Jun. 30, 2011

Other Income and Expenses

Other Income and Expenses

Note 16. Other Income and Expenses

Other income and expenses are as follows:

		Three months ended June 30,				Six months ended June 30,
(in millions)		2011		2010		2011		2010
Other income:
	Equity AFUDC	$	27	$	25	$	56	$	54
	Increase in cash surrender value of life insurance policies		7		6		13		12
	Other		5		4		8		4
Total utility other income			39		35		77		70
Competitive power generation and other income			3		1		6		—
Total other income		$	42	$	36	$	83	$	70
Other expenses:
	Civic, political and related activities and donations	$	9	$	9	$	15	$	15
	Other		4		6		10		11
Total utility other expenses			13		15		25		26
Competitive power generation and other expenses			—		1		—		2
Total other expenses		$	13	$	16	$	25	$	28

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Fair Value Measurements (Details 2) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Fair Value of Long-Term Debt Recorded at Carrying Value
Long-term debt, including current portion, carrying amount	$ 13,009	$ 12,419
Long-term debt, including current portion, fair value	$ 13,075	$ 12,360

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2011

Summary of Significant Accounting Policies

Cash Equivalents

Cash Equivalents

Cash equivalents included investments in money market funds totaling $743 million and $1.1 billion at June 30, 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 $185 million and $197 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at June 30, 2011 and December 31, 2010, respectively.

Inventory

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.

Earnings Per Share

Earnings Per Share

Edison International computes earnings per share ("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 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.

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2011

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

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 ("GAAP") for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and six-month periods ended June 30, 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 GAAP.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $743 million and $1.1 billion at June 30, 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 $185 million and $197 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at June 30, 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)	June 30, 2011		December 31, 2010
Coal, gas, fuel oil and other raw materials	$	203	$	184
Spare parts, materials and supplies		386		384
Total inventory	$	589	$	568

Earnings Per Share

Edison International computes earnings per share ("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 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 June 30,					Six months ended June 30,
(in millions)	2011		2010			2011		2010
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	177	$	343		$	379	$	572
Participating securities dividends		—		(2	)		—		(2	)
Income from continuing operations available to common shareholders	$	177	$	341		$	379	$	570
Weighted average common shares outstanding		326		326			326		326
Basic earnings per share – continuing operations	$	0.54	$	1.05		$	1.16	$	1.75
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	177	$	341		$	379	$	570
Income impact of assumed conversions		1		1			1		1
Income from continuing operations available to common shareholders and assumed conversions	$	178	$	342		$	380	$	571
Weighted average common shares outstanding		326		326			326		326
Incremental shares from assumed conversions		3		1			2		1
Adjusted weighted average shares – diluted		329		327			328		327
Diluted earnings per share – continuing operations	$	0.54	$	1.05		$	1.16	$	1.75

Stock-based compensation awards to purchase 5,896,940 and 9,645,334 shares of common stock for the three months ended June 30, 2011 and 2010, respectively, and 5,896,940 and 6,080,199 shares of common stock for the six months ended June 30, 2011 and 2010 respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares during the respective periods 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.

Accounting Guidance Not Yet Adopted

Fair Value Measurement

In May 2011, the FASB issued an accounting standards update modifying the fair value measurement and disclosure guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the value be based on the individual security. This amendment also results in new disclosures primarily related to Level 3 measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. Edison International will adopt this guidance effective January 1, 2012 and does not expect the adoption of this standard will have a material impact on Edison International's consolidated statements of income, financial position or cash flows.

Presentation of Comprehensive Income

In June 2011, the FASB issued an accounting standards update on the presentation of comprehensive income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. Edison International will adopt this guidance effective January 1, 2012. Edison International currently presents the statement of comprehensive income immediately following the statement of income and expects to continue to do so. The adoption of this accounting standards update does not change the items that constitute net income and other comprehensive income.

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Regulatory and Environmental Developments

6 Months Ended

Jun. 30, 2011

Regulatory and Environmental Developments

Regulatory and Environmental Developments

Note 10. Regulatory and Environmental Developments

Environmental Developments

Cross-State Air Pollution Rule

On July 6, 2011, the US EPA adopted its final Cross-State Air Pollution Rule ("CSAPR") which will replace the Clean Air Interstate Rule ("CAIR") beginning on January 1, 2012. CSAPR is the final form of a previously proposed replacement for the CAIR, called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual sulfur dioxide ("SO₂") emissions and annual ozone season nitrogen oxide ("NO_x") emissions in two phases: a first phase effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO₂ emissions.

CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO₂ or NO_x emissions from operations will need to be matched by a sufficient amount of SO₂ or NO_x allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO₂ and NO_x allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual compliance period, units must surrender allowances for each ton of SO₂ and NO_x emitted or face penalties. While trading of allowances is permitted within designated groups of states, the rule provides for enhanced penalties against a unit that surrenders allowances in excess of certain predefined limits for itself and for the state in which it is located.

The installation of SO₂ controls will require capital commitments for the Midwest Generation plants well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. EMG believes that Midwest Generation's current environmental remediation plan, including allocated allowances and capital expenditures, required to meet the CPS will also comply with the requirements of CSAPR. However, the SO₂ allowances allocated to Homer City in CSAPR Phase I (25,797 tons in 2012 and 2013) are significantly lower than the amount that would be required based on Homer City's historical emissions (2010 SO₂ emissions were 112,951 tons). Therefore, pending installation of additional equipment for Units 1 and 2 (Homer City's Unit 3 is equipped with a wet scrubber flue gas desulfurization system to meet environmental standards), Homer City expects that it will be required to procure additional allowances. It is unclear at this time whether SO₂ allowances in sufficient quantity and at prices that Homer City can pass through in power prices will be available in 2012 and 2013. Also, Homer City's SO₂ shortfall is expected to exceed limits on the number of allowances it will be permitted to surrender, and, therefore, may subject Homer City to penalties in certain cases. Accordingly, Homer City is evaluating alternative options, including reduced dispatch and fuel switching, for complying with Phase I of CSAPR. Failure by Homer City to develop and implement a Phase I compliance plan based on allowances could result in its modifying operations at one or more units or significantly curtailing power output. The cost of allowances, together with possible operational impacts or reductions of output, which may be required to comply with Phase I of CSAPR, could have a material effect on Homer City.

Homer City has begun work on designing SO₂ and particulate emissions control equipment for Units 1 and 2. While the Phase II SO₂ emission allowances under CSAPR (11,068 tons) are less than were contemplated under the proposed Clean Air Transport Rule, the additional reductions are not expected to materially change the design for the SO₂ controls at Units 1 and 2. The installation of those SO₂ controls will require capital commitments for the Homer City plant well in advance of the 2014 effective date, some of which will be expended in 2011, in order to meet regulatory deadlines. Given the relatively short period of time before Phase II of CSAPR takes effect in 2014, there is no assurance that Homer City will be able to complete all the work that will be required before the deadline. Homer City is continuing to review technologies available to reduce SO₂ and mercury emissions; however, it has not determined the most effective and efficient technology to meet all requirements that may be imposed on it. Consequently, the timing, selection of technology and ultimate capital costs remain uncertain. Based on preliminary estimates, Homer City currently believes the cost of such equipment may be between $600 million and $700 million.

Homer City does not currently have sufficient capital and does not expect to generate sufficient capital from operations to fund such retrofits and will have to seek financing, which will be subject to decisions by Homer City's lessors, holders of the pass-through certificates and new providers of capital funding. There is no assurance that sufficient financing will be obtained or will not result in significant dilution of Homer City's interest in the Homer City plant.

Proposed Hazardous Air Pollutant Regulations

In March 2011, the US EPA issued proposed National Emission Standards for Hazardous Air Pollutants, limiting emissions of hazardous air pollutants from coal- and oil-fired electrical generating units. This regulation is expected to be finalized by November 2011. Based on its continuing review, EMG does not expect that these standards, if adopted as proposed, 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. EMG also does not expect that these standards, if adopted as proposed, would require Homer City to make additional capital requirements beyond those that would be required to comply with CSAPR.

Water Quality

Once-Through Cooling Issues

In March 2011, the US EPA issued proposed 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 evaluating the proposed standards and believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable for both the Midwest Generation plants and the Homer City plant without incurring material additional capital expenditures or operating costs. 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. If other coastal power plants in California that rely on once-through cooling are forced to shut down or limit operations, the California policy may also significantly impact SCE's ability to procure generating capacity from those plants, which could have an adverse effect on system reliability and the cost of electricity.

Greenhouse Gas Regulation

California Air Resources Board's ("CARB") regulations implementing a California cap-and-trade program continue to be the subject of litigation. In June 2011, the CARB announced that initial cap-and-trade program compliance for the electricity sector would be delayed until January 2013.

In April 2011, California enacted a law requiring that California utilities to procure 33% of their electricity requirements from renewable resources, as defined in the statute. The law requires implementation by the CPUC. The impact of the new 33% law will depend on how the CPUC implements the law, which remains uncertain.

Greenhouse Gas Litigation Developments

In June 2011, the U.S. Supreme Court dismissed public nuisance claims against five power companies, ruling that the CAA and the US EPA actions it authorizes displace federal common law nuisance claims that might arise from the emission of greenhouse gases. The court also affirmed the Second Circuit's determination that at least some of the plaintiffs had standing to bring the case. The court did not address whether the CAA also preempts state law claims arising from the same circumstances.

Parties to the Kivalina case, the appeal of which was deferred before the Ninth Circuit Court of Appeals pending the Supreme Court's ruling described above, have requested that the appeal recommence and have asked for permission to file additional briefs on the impact of the Supreme Court's ruling. The Kivalina case was brought by the Alaskan Native Village of Kivalina seeking damages of up to $400 million for the cost of relocating the village because the plaintiffs claim that the Arctic ice that has protected the village is melting as a result of climate change. The federal district court dismissed the case against Edison International and the other defendants in October 2009. Due to the nature of these potential obligations, Edison International is unable to estimate the potential liability, if any.

On May 27, 2011, private citizens filed a purported class action complaint in the United States District Court for the Southern District of Mississippi, naming among a large number of defendants, Edison International and its subsidiaries, including SCE and EME. Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of greenhouse gases that have contributed to climate change and sea level rise, which in turn are alleged to have increased the destructive force of Hurricane Katrina. The lawsuit alleges causes of action for negligence, public and private nuisance, and trespass, and seeks unspecified compensatory and punitive damages. The claims in this lawsuit are nearly identical to a subset of the claims that were raised against many of the same defendants in a previous lawsuit that was filed in, and dismissed by, the same federal district court where the current case has been filed.

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Accumulated Other Comprehensive (Loss) (Details) (USD $) In Millions	3 Months Ended		6 Months Ended						6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011 Unrealized Gain (Loss) on Cash Flow Hedges	Jun. 30, 2011 Pension and PBOP- Net Gain (Loss)	Jun. 30, 2011 Pension and PBOP- Prior Service Cost	Dec. 31, 2010 Pension and PBOP- Prior Service Cost	Jun. 30, 2011 Commodity contracts	Jun. 30, 2011 Interest rate contracts
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance, at the beginning of period			$ (76)		$ 16	$ (87)	$ (5)	$ (5)
Current period change	(20)	(128)	(21)	(49)	(25)	4
Balance, at the end of period	(97)		(97)		(9)	(83)	(5)	(5)
Unrealized derivative losses after taxes recorded in accumulated other comprehensive income									(4)	13
Unrealized gains on cash flow hedges, net of tax, expected to be reclassified into earnings during the next 12 months									$ 8

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Other Investments (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	$ 2,256,000,000		$ 2,256,000,000		$ 2,185,000,000
Fair Value	3,657,000,000	3,083,000,000	3,657,000,000	3,083,000,000	3,480,000,000
Proceeds from sale of securities	524,000,000	315,000,000	1,146,000,000	600,000,000
Unrealized Holding Gains Net of Losses on Investments in Trust			1,400,000,000		1,300,000,000
Summary of changes in the fair value of the trust
Balance at beginning of period	3,619,000,000	3,248,000,000	3,480,000,000	3,140,000,000	3,140,000,000
Realized gains - net	12,000,000	13,000,000	35,000,000	34,000,000
Unrealized gains (losses) - net	4,000,000	(205,000,000)	106,000,000	(143,000,000)
Other-than-temporary impairments	(4,000,000)	(7,000,000)	(13,000,000)	(11,000,000)
Interest, dividends, contributions and other	26,000,000	34,000,000	49,000,000	63,000,000
Balance at end of period	3,657,000,000	3,083,000,000	3,657,000,000	3,083,000,000	3,480,000,000
Southern California Edison Company
Fair Value Disclosures:
Contributions received for decommissioning trusts			23,000,000
Period of reviewing contributions from decommissioning trusts (in years)			3Y
Stocks
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	862,000,000		862,000,000		895,000,000
Fair Value	2,062,000,000		2,062,000,000		2,029,000,000
Summary of changes in the fair value of the trust
Balance at end of period	2,062,000,000		2,062,000,000		2,029,000,000
Municipal bonds
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments			2050
Amortized Cost	699,000,000		699,000,000		706,000,000
Fair Value	812,000,000		812,000,000
Summary of changes in the fair value of the trust
Balance at beginning of period			790,000,000
Balance at end of period	812,000,000		812,000,000
U.S. government and agency securities
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments			2041
Amortized Cost	396,000,000		396,000,000		270,000,000
Fair Value	427,000,000		427,000,000
Summary of changes in the fair value of the trust
Balance at beginning of period			288,000,000
Balance at end of period	427,000,000		427,000,000
Corporate bonds
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments			2054
Amortized Cost	255,000,000		255,000,000		288,000,000
Fair Value	310,000,000		310,000,000
Summary of changes in the fair value of the trust
Balance at beginning of period			346,000,000
Balance at end of period	310,000,000		310,000,000
Short-term investments, primarily cash equivalents
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments			One-year
Amortized Cost	44,000,000		44,000,000		26,000,000
Fair Value	46,000,000		46,000,000
Summary of changes in the fair value of the trust
Balance at beginning of period			27,000,000
Balance at end of period	$ 46,000,000		$ 46,000,000

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Regulatory Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2011

Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets

(in millions)		June 30, 2011		December 31, 2010
Current:
	Regulatory balancing accounts	$	268	$	213
	Energy derivatives		194		162
	Other		7		3
			469		378
Long-term:
	Deferred income taxes – net		1,912		1,855
	Pensions and other postretirement benefits		1,089		1,097
	Unamortized generation investment – net		328		355
	Unamortized loss on reacquired debt		258		268
	Energy derivatives		465		177
	Nuclear-related ARO investment – net		163		154
	Unamortized distribution investment – net		125		105
	Regulatory balancing accounts		53		56
	Other		297		280
			4,690		4,347
Total Regulatory Assets		$	5,159	$	4,725

Regulatory liabilities included on the consolidated balance sheets

(in millions)	June 30, 2011		December 31, 2010
Current:
Regulatory balancing accounts	$	818	$	733
Other		2		5
		820		738
Long-term:
Costs of removal		2,663		2,623
ARO		1,250		1,099
Regulatory balancing accounts		846		802
		4,759		4,524
Total Regulatory Liabilities	$	5,579	$	5,262

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Regulatory Assets and Liabilities

6 Months Ended

Jun. 30, 2011

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

Note 14. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)		June 30, 2011		December 31, 2010
Current:
	Regulatory balancing accounts	$	268	$	213
	Energy derivatives		194		162
	Other		7		3
			469		378
Long-term:
	Deferred income taxes – net		1,912		1,855
	Pensions and other postretirement benefits		1,089		1,097
	Unamortized generation investment – net		328		355
	Unamortized loss on reacquired debt		258		268
	Energy derivatives		465		177
	Nuclear-related ARO investment – net		163		154
	Unamortized distribution investment – net		125		105
	Regulatory balancing accounts		53		56
	Other		297		280
			4,690		4,347
Total Regulatory Assets		$	5,159	$	4,725

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	June 30, 2011		December 31, 2010
Current:
Regulatory balancing accounts	$	818	$	733
Other		2		5
		820		738
Long-term:
Costs of removal		2,663		2,623
ARO		1,250		1,099
Regulatory balancing accounts		846		802
		4,759		4,524
Total Regulatory Liabilities	$	5,579	$	5,262

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Consolidated Statements of Comprehensive Income (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Net income	$ 191	$ 357	$ 405	$ 606
Pension and postretirement benefits other than pensions:
Net gain arising during the period, net of income tax expense of $2 for the six months ended June 30, 2010				12
Amortization of net (gain) loss included in net income, net of income tax expense (benefit) of $1 and $1 for the three months and $3 and $(4) for the six months ended June 30, 2011 and 2010, respectively	1	2	4	(6)
Prior service credit arising during the period, net of income tax expense of $1 for the six months ended June 30, 2010				2
Amortization of prior service credit, net of income tax benefit of $1 for the six months ended June 30, 2010				(2)
Unrealized gain (loss) on derivatives qualified as cash flow hedges:
Unrealized holding gain (loss) arising during the period, net of income tax expense (benefit) of $(9) and $(50) for the three months and $(5) and $12 for the six months ended June 30, 2011 and 2010, respectively	(14)	(77)	(8)	18
Reclassification adjustments included in net income, net of income tax benefit of $6 and $35 for the three months and $12 and $49 for the six months ended June 30, 2011 and 2010, respectively	(7)	(53)	(17)	(73)
Other comprehensive loss	(20)	(128)	(21)	(49)
Comprehensive income	171	229	384	557
Less: Comprehensive income attributable to noncontrolling interests	15	13	29	26
Comprehensive income attributable to Edison International	$ 156	$ 216	$ 355	$ 531

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Other Income and Expenses (Tables)

6 Months Ended

Jun. 30, 2011

Other Income and Expenses

Other Income and Expenses

		Three months ended June 30,				Six months ended June 30,
(in millions)		2011		2010		2011		2010
Other income:
	Equity AFUDC	$	27	$	25	$	56	$	54
	Increase in cash surrender value of life insurance policies		7		6		13		12
	Other		5		4		8		4
Total utility other income			39		35		77		70
Competitive power generation and other income			3		1		6		—
Total other income		$	42	$	36	$	83	$	70
Other expenses:
	Civic, political and related activities and donations	$	9	$	9	$	15	$	15
	Other		4		6		10		11
Total utility other expenses			13		15		25		26
Competitive power generation and other expenses			—		1		—		2
Total other expenses		$	13	$	16	$	25	$	28

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Effective Tax Rate
Income from continuing operations before income taxes	$ 254	$ 220		$ 535	$ 612
Federal statutory rate (as a percent)	35.00%	35.00%		35.00%	35.00%
Provision for income tax at federal statutory rate	89	77		187	214
Items presented with related state income tax, net
Global Settlement related		(138)			(138)
Change in tax accounting method for asset removal costs		(40)			(40)
State tax - net of federal benefit	4	16		13	23
Health care legislation					39
Production and housing credits	(19)	(19)		(36)	(34)
Property-related and other	(12)	(32)		(37)	(50)
Total income tax expense from continuing operations	62	(136)		127	14
Effective tax rate (as a percent)	24.00%	(62.00%)		24.00%	2.00%
Non-cash charge to reverse previously recognized federal tax benefits			39
Change in Tax Accounting Method for Asset Removal Costs
Asset removal costs relating to prior periods		(28)			(28)
Unrecognized Tax Benefits
Unrecognized tax benefits, beginning balance			664	565	664
Unrecognized tax benefits, increases resulting from current period tax positions				26	35
Unrecognized tax benefits, increases resulting from prior period tax positions				14	127
Unrecognized tax benefits, decreases resulting from prior period tax positions				(10)	(40)
Unrecognized tax benefits, decreases resulting from settlements with taxing authorities					(82)
Unrecognized tax benefits, ending balance	595	704		595	704
Unrecognized tax benefits that would impact effective tax rate	468			468		455
Accrued Interest and Penalties
Accrued interest and penalties	222			222		213
Net after-tax interest income and penalties recognized in income tax expense (benefit)	(2)	101		(5)	88
Southern California Edison Company | IRS Examination
Settlement of Tax Disputes
Estimated potential future federal tax payment as of the balance sheet date, including interest and penalties, based on a proposed adjustment	91			91
IRS Examination
Settlement of Tax Disputes
Estimated potential future federal tax payment as of the balance sheet date, including interest and penalties, based on a proposed adjustment	$ 189			$ 189
Penalty for understatement of tax liability (as a percent)				40.00%

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Preferred and Preference Stock of Utility (Details) (Southern California Edison Company, 6.5% Series D preference stock, USD $)	1 Months Ended
	Mar. 31, 2011
Southern California Edison Company | 6.5% Series D preference stock
Preferred and Preference Stock of Utility
Shares issued (in shares)	1,250,000
Preferred stock (as a percent)	6.50%
Preference share, liquidation value (in dollars per share)	$ 100

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Debt and Credit Agreements (Details) (USD $)							1 Months Ended					1 Months Ended							1 Months Ended		1 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2011 Southern California Edison Company Letters of Credit	Jun. 30, 2011 Edison Mission Energy Letters of Credit	Jun. 30, 2011 Letters of Credit	Jun. 30, 2011 Letters of Credit Midwest Generation LLC.	Feb. 28, 2011 Letters of Credit Viento Funding II, Inc.	Jun. 30, 2011 Edison International Short-term debt	Dec. 31, 2010 Edison International Short-term debt	Jun. 30, 2011 Southern California Edison Company Short-term debt	Jun. 30, 2011 Southern California Edison Company Revolving credit facility	Feb. 28, 2011 Term Loan due 2020 Viento Funding II, Inc.	Feb. 28, 2011 Working capital facility Viento Funding II, Inc.	May 31, 2011 Southern California Edison Company First and refunding mortgage bonds due in 2021	Jul. 31, 2011 Primary term loan Walnut Creek project	Jul. 31, 2011 Intermediate holding company loan Walnut Creek project	May 31, 2011 Southern California Edison Company Tax-exempt pollution control bonds	Jun. 30, 2011 Southern California Edison Company	Feb. 28, 2011 Viento Funding II, Inc.	Jun. 30, 2011 Viento Funding II, Inc.	Jul. 31, 2011 Walnut Creek project mW	Jul. 31, 2011 Walnut Creek project Forward swap due 2013	Jul. 31, 2011 Walnut Creek project Forward swap due 2023
Debt Instrument:
Bonds issued														$ 500,000,000
Interest rate on debt (as a percent)														3.875%
Purchase of tax-exempt bonds subject to remarketing																	56,000,000
Power generating capacity for natural gas-fired peaker plant (in megawatts)																					479
Construction loan																					495,000,000
Initial fundings of construction loan																					48,000,000
Project-level construction term loan															442,000,000	53,000,000
Period of amortizing term loan that the financing is required to be converted (in years)																					10
Letters of credit and working capital facilities																					122,000,000
Floating interest rate received															LIBOR	LIBOR			LIBOR
Variable rate, spread (as a percent)															2.25%	4.00%			2.75%
Variable rate, incremental spread after every third, sixth and ninth year (as a percent)																					0.25%
Debt, face amount							23,000,000					227,000,000	5,000,000						255,000,000
Maturity period of debt instruments (in years)							7					10	7
Long-term debt - Gross																				216,000,000
Letters of credit outstanding																		39,000,000		23,000,000
Variable rate, incremental spread (as a percent)																			0.25%
Outstanding short-term borrowing	388,000,000	115,000,000						79,000,000	19,000,000	200,000,000
Weighted average interest rate (as a percent)								0.55%	0.63%	0.33%
Credit facility											2,400,000,000
Letters of credit expiring in 12 months or less			71,000,000
Standby letters of credit outstanding				116,000,000	51,000,000	3,000,000
Standby letters of credit expiring in 2011				39,000,000	7,000,000
Standby letters of credit expiring in 2012				77,000,000	16,000,000
Standby letters of credit expiring in 2017					10,000,000
Standby letters of credit expiring in 2018					$ 18,000,000
Forward starting interest rate, low end (as a percentage)																						0.79%
Forward starting interest rate, high end (as a percentage)																						0.81%
Fixed interest rate paid (as a percent)																							3.59%

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Derivative Instruments and Hedging Activities (Details) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	$ 117	$ 133
Long-Term, Derivative Assets	242	437
Short-Term, Derivative Liabilities	238	217
Long-Term, Derivative Liabilities	580	468
Commodity contracts | Electric Utility
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	78	87
Long-Term, Derivative Assets	179	367
Derivative Assets, Total	257	454
Short-Term, Derivative Liabilities	231	212
Long-Term, Derivative Liabilities	558	449
Derivative Liabilities, Total	789	661
Net Asset (Liability)	(532)	(207)
Commodity contracts | Electric Utility | Economic hedges
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	89	87
Long-Term, Derivative Assets	200	367
Derivative Assets, Total	289	454
Short-Term, Derivative Liabilities	243	216
Long-Term, Derivative Liabilities	579	449
Derivative Liabilities, Total	822	665
Net Asset (Liability)	(533)	(211)
Commodity contracts | Electric Utility | Netting and Collateral
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	(11)
Long-Term, Derivative Assets	(21)
Derivative Assets, Total	(32)
Short-Term, Derivative Liabilities	(12)	(4)
Long-Term, Derivative Liabilities	(21)
Derivative Liabilities, Total	(33)	(4)
Net Asset (Liability)	1	4
Competitive power generation
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	39	46
Long-Term, Derivative Assets	63	70
Derivative Assets, Total	102	116
Short-Term, Derivative Liabilities	6	6
Long-Term, Derivative Liabilities	23	19
Derivative Liabilities, Total	29	25
Net Asset (Liability)	73	91
Competitive power generation | Trading and Non-trading activities
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	228	315
Long-Term, Derivative Assets	94	107
Derivative Assets, Total	322	422
Short-Term, Derivative Liabilities	163	229
Long-Term, Derivative Liabilities	55	54
Derivative Liabilities, Total	218	283
Net Asset (Liability)	104	139
Competitive power generation | Cash flow hedges
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	27	54
Long-Term, Derivative Assets	2	2
Derivative Assets, Total	29	56
Short-Term, Derivative Liabilities	14	10
Long-Term, Derivative Liabilities	34	25
Derivative Liabilities, Total	48	35
Net Asset (Liability)	(19)	21
Competitive power generation | Economic hedges
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	60	77
Long-Term, Derivative Assets	4	2
Derivative Assets, Total	64	79
Short-Term, Derivative Liabilities	51	71
Long-Term, Derivative Liabilities	1
Derivative Liabilities, Total	52	71
Net Asset (Liability)	12	8
Competitive power generation | Trading activities
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	141	184
Long-Term, Derivative Assets	88	103
Derivative Assets, Total	229	287
Short-Term, Derivative Liabilities	98	148
Long-Term, Derivative Liabilities	20	29
Derivative Liabilities, Total	118	177
Net Asset (Liability)	111	110
Competitive power generation | Netting and Collateral
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	(189)	(269)
Long-Term, Derivative Assets	(31)	(37)
Derivative Assets, Total	(220)	(306)
Short-Term, Derivative Liabilities	(157)	(223)
Long-Term, Derivative Liabilities	(32)	(35)
Derivative Liabilities, Total	(189)	(258)
Net Asset (Liability)	$ (31)	$ (48)

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Regulatory and Environmental Developments (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended	1 Months Ended	6 Months Ended	1 Months Ended
	Jun. 30, 2011	Apr. 30, 2011 Southern California Edison Company	Jun. 30, 2011 Homer City	Jun. 30, 2011 Greenhouse Gas Litigation Developments	Oct. 31, 2009 Kivalina case
Regulatory and environmental developments
Electricity requirements required to be purchased as per the law enacted by legislature (as a percent)		33.00%
Number of power companies against whom public nuisance claims are dismissed				5
Damages sought in Kivalina case					$ 400
Estimated capital costs for SO2 reduction, high end of the range			700
SO2 allowances allocated in CSAPR Phase I in second year (in tons)	25,797
SO2 allowances allocated in CSAPR Phase I in third year (in tons)	25,797
SO2 allowances allocated in CSAPR Phase I in current year (in tons)	112,951
SO2 allowances allocated in CSAPR Phase II (in tons)	11,068
Estimated capital costs for SO2 reduction, low end of the range			$ 600

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Business Segments (Tables)

6 Months Ended

Jun. 30, 2011

Business Segments

Segment income statement information

	Three months ended June 30,						Six months ended June 30,
(in millions)	2011			2010			2011			2010
Operating Revenue:
Electric utility	$	2,446		$	2,247		$	4,678		$	4,406
Competitive power generation		538			495			1,090			1,147
Parent and other2		(1	)		(1	)		(2	)		(1	)
Consolidated Edison International	$	2,983		$	2,741		$	5,766		$	5,552
Net Income (Loss) attributable to Edison International:
Electric utility	$	211		$	301		$	433		$	465
Competitive power generation1		(31	)		27			(51	)		104
Parent and other2		(4	)		16			(6	)		11
Consolidated Edison International	$	176		$	344		$	376		$	580

¹

Includes earnings (losses) from discontinued operations of $(1) million and $1 million for the three months ended June 30, 2011 and 2010, respectively, and $(3) million and $8 million for the six months ended June 30, 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.

Segment balance sheet information

(in millions)		June 30, 2011			December 31, 2010
Total Assets:
	Electric utility	$	37,365		$	35,906
	Competitive power generation		9,804			9,597
	Parent and other2		(94	)		27
Consolidated Edison International		$	47,075		$	45,530

¹

Includes earnings (losses) from discontinued operations of $(1) million and $1 million for the three months ended June 30, 2011 and 2010, respectively, and $(3) million and $8 million for the six months ended June 30, 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.