10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________

FORM 10-Q

____________________________________________________

(Mark One)
S	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2011
£	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 S No £

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 S No £

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 S Accelerated filer £ Non-accelerated filer £ (Do not check if a smaller reporting company) Smaller reporting company £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes £ No S

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 October 31, 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	11
Note 5. Debt and Credit Agreements	15
Note 6. Derivative Instruments and Hedging Activities	16
Note 7. Income Taxes	22
Note 8. Compensation and Benefit Plans	24
Note 9. Commitments and Contingencies	26
Note 10. Regulatory and Environmental Developments	32
Note 11. Accumulated Other Comprehensive Loss	34
Note 12. Supplemental Cash Flows Information	35
Note 13. Preferred and Preference Stock of Utility	35
Note 14. Regulatory Assets and Liabilities	36
Note 15. Other Investments	37
Note 16. Other Income and Expenses	38
Note 17. Business Segments	38
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	40
FORWARD-LOOKING STATEMENTS	40
EDISON INTERNATIONAL MANAGEMENT OVERVIEW
Highlights of Operating Results	42
Management Overview of SCE	43
Capital Program	43
2012 CPUC General Rate Case	43
FERC Formula Rates	44
Nuclear Industry and Regulatory Response to Events in Japan	44
Management Overview of EMG	44
Cross-State Air Pollution Rule	45
Homer City Capital Needs and Liquidity	45
Midwest Generation Environmental Compliance Plans and Costs	46
Environmental Regulation Developments	47
SOUTHERN CALIFORNIA EDISON COMPANY
RESULTS OF OPERATIONS	48
Three Months Ended September 30, 2011 versus September 30, 2010	48
Utility Earning Activities	49
Utility Cost-Recovery Activities	49

i

Nine Months Ended September 30, 2011 versus September 30, 2010	50
Utility Earning Activities	50
Utility Cost-Recovery Activities	51
Supplemental Operating Revenue Information	51
Income Taxes	51
Repair Deductions	52
LIQUIDITY AND CAPITAL RESOURCES	52
Available Liquidity	52
Debt Covenant	52
Dividend Restrictions	52
Regulatory Proceedings	53
Energy Efficiency Shareholder Risk/Reward Mechanism	53
Cost of Capital	53
Margin and Collateral Deposits	53
Workers Compensation Self-Insurance Fund	53
Historical Consolidated Cash Flows	54
Condensed Consolidated Statement of Cash Flows	54
Net Cash Provided by Operating Activities	54
Net Cash Provided by Financing Activities	54
Net Cash Used by Investing Activities	54
Contractual Obligations and Contingencies	55
Contractual Obligations	55
Contingencies	55
Environmental Remediation	55
MARKET RISK EXPOSURES	55
Commodity Price Risk	55
Credit Risk	55
EDISON MISSION GROUP
RESULTS OF OPERATIONS	57
Results of Continuing Operations	57
Adjusted Operating Income ("AOI")—Overview	59
Adjusted Operating Income from Consolidated Operations	60
Midwest Generation Plants	60
Homer City	61
Seasonality—Coal Plants	61
Renewable Energy Projects	62
Energy Trading	62
Adjusted Operating Income from Other Projects	62
Interest Expense	63
Income Taxes	63
LIQUIDITY AND CAPITAL RESOURCES	64
Available Liquidity	64
Homer City Outage	64
Capital Investment Plan	65
Environmental Capital Expenditures	65
Plant Capital Expenditures	66
Renewable Energy Projects	66

ii

Funding of Capital Expenditures	66
Historical Segment Cash Flows	66
Condensed Statement of Cash Flows	66
Net Cash Provided by Operating Activities	66
Net Cash Provided by Financing Activities	66
Net Cash Provided by Investing Activities	67
Credit Ratings	67
Overview	67
Credit Rating of EMMT	67
Margin, Collateral Deposits and Other Credit Support for Energy Contracts	67
Debt Covenants and Dividend Restrictions	68
Credit Facility Financial Ratios	68
Key Ratios of EMG's Principal Subsidiaries Affecting Dividends	68
EME's Senior Notes and Guaranty of Powerton-Joliet Leases	68
Contractual Obligations and Contingencies	69
Fuel Supply Contracts and Coal Transportation Agreements	69
Turbine Commitments	69
Capital Commitments	69
Midwest Generation New Source Review and Other Litigation	69
Homer City New Source Review and Other Litigation	69
Off-Balance Sheet Transactions	69
MARKET RISK EXPOSURES	69
Derivative Instruments	70
Unrealized Gains and Losses	70
Fair Value Disclosures	70
Commodity Price Risk	70
Energy Price Risk	70
Capacity Price Risk	72
Basis Risk	72
Coal and Transportation Price Risk	73
Emission Allowances Price Risk	73
Credit Risk	74
Interest Rate Risk	74
EDISON INTERNATIONAL PARENT AND OTHER
RESULTS OF OPERATIONS	75
LIQUIDITY AND CAPITAL RESOURCES	75
Historical Cash Flows	75
Condensed Statement of Cash Flows	75
Net Cash Used by Operating Activities	75
Net Cash Provided (Used) by Financing Activities	76
EDISON INTERNATIONAL (CONSOLIDATED)
LIQUIDITY AND CAPITAL RESOURCES	77
Contractual Obligations	77
CRITICAL ACCOUNTING ESTIMATES AND POLICIES	77
NEW ACCOUNTING GUIDANCE	77
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	77
ITEM 4. CONTROLS AND PROCEDURES	77

iii

Disclosure Controls and Procedures	77
Internal Control Over Financial Reporting	77
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	77
California Coastal Commission Potential Environmental Proceeding	77
Navajo Nation Litigation	78
Midwest Generation New Source Review and Other Litigation	78
Homer City New Source Review and Other Litigation	78
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	78
Purchases of Equity Securities by the Issuer and Affiliated Purchasers	78
ITEM 5. OTHER INFORMATION	79
ITEM 6. EXHIBITS	79
SIGNATURE	80

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.

v

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
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, a Delaware limited liability company that owns and/or leases, and that operates, the Midwest Generation plants
Midwest Generation plants	Midwest Generation'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

vi

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

vii

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Statements of Income	Edison International
	Three months ended September 30,						Nine months ended September 30,
(in millions, except per-share amounts, unaudited)	2011			2010			2011			2010
Electric utility	$	3,385		$	3,097		$	8,060		$	7,502
Competitive power generation	596			691			1,686			1,838
Total operating revenue	3,981			3,788			9,746			9,340
Fuel	352			328			866			877
Purchased power	1,264			1,118			2,422			2,337
Operations and maintenance	1,119			1,102			3,531			3,287
Depreciation, decommissioning and amortization	436			378			1,288			1,127
Total operating expenses	3,171			2,926			8,107			7,628
Operating income	810			862			1,639			1,712
Interest and dividend income	4			4			38			27
Equity in income from unconsolidated affiliates – net	56			62			68			101
Other income	27			33			110			103
Interest expense	(203		)	(175		)	(601		)	(518		)
Other expenses	(11		)	(12		)	(37		)	(39		)
Income from continuing operations before income taxes	683			774			1,217			1,386
Income tax expense	242			247			369			261
Income from continuing operations	441			527			848			1,125
Income (loss) from discontinued operations – net of tax	—			(4		)	(3		)	4
Net income	441			523			845			1,129
Dividends on preferred and preference stock of utility	15			13			44			39
Other noncontrolling interests	—			—			(1		)	—
Net income attributable to Edison International common shareholders	$	426		$	510		$	802		$	1,090
Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	$	426		$	514		$	805		$	1,086
Income (loss) from discontinued operations, net of tax	—			(4		)	(3		)	4
Net income attributable to Edison International common shareholders	$	426		$	510		$	802		$	1,090
Basic earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding	326			326			326			326
Continuing operations	$	1.31		$	1.57		$	2.47		$	3.32
Discontinued operations	—			(0.01		)	(0.01		)	0.01
Total	$	1.31		$	1.56		$	2.46		$	3.33
Diluted earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities	329			328			329			328
Continuing operations	$	1.30		$	1.57		$	2.46		$	3.30
Discontinued operations	—			(0.01		)	(0.01		)	0.01
Total	$	1.30		$	1.56		$	2.45		$	3.31
Dividends declared per common share	$	0.320		$	0.315		$	0.960		$	0.945

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

1

Consolidated Statements of Comprehensive Income				Edison International
	Three months ended September 30,						Nine months ended September 30,
(in millions, unaudited)	2011			2010			2011			2010
Net income	$	441		$	523		$	845		$	1,129
Other comprehensive income (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 nine months ended September 30, 2010	—			1			—			13
Amortization of net (gain) loss included in net income, net of income tax expense (benefit) of $1 and $1 for the three months and $4 and $(3) for the nine months ended September 30, 2011 and 2010, respectively	3			1			7			(5		)
Prior service credit arising during the period, net of income tax expense of $1 for the nine months ended September 30, 2010	—			—			—			2
Amortization of prior service credit, net of income tax benefit of $1 for the nine months ended September 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 $(19) and $29 for the three months and $(24) and $41 for the nine months ended September 30, 2011 and 2010, respectively	(30		)	43			(38		)	61
Reclassification adjustments included in net loss, net of income tax benefit of none and $5 for the three months and $12 and $54 for the nine months ended September 30, 2011 and 2010, respectively	—			(7		)	(17		)	(80		)
Other comprehensive income (loss)	(27		)	38			(48		)	(11		)
Comprehensive income	414			561			797			1,118
Less: Comprehensive income attributable to noncontrolling interests	15			13			43			39
Comprehensive income attributable to Edison International	$	399		$	548		$	754		$	1,079

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

2

Consolidated Balance Sheets	Edison International
(in millions, unaudited)	September 30, 2011		December 31, 2010
ASSETS
Cash and cash equivalents	$	1,384	$	1,389
Receivables, less allowances of $97 and $85 for uncollectible accounts at respective dates	1,218		931
Accrued unbilled revenue	709		442
Inventory	592		568
Prepaid taxes	72		390
Derivative assets	100		133
Restricted cash	15		2
Margin and collateral deposits	54		65
Regulatory assets	454		378
Other current assets	153		124
Total current assets	4,751		4,422
Nuclear decommissioning trusts	3,393		3,480
Investments in unconsolidated affiliates	569		559
Other investments	231		223
Total investments	4,193		4,262
Utility property, plant and equipment, less accumulated depreciation of $6,745 and $6,319 at respective dates	26,490		24,778
Competitive power generation and other property, plant and equipment, less accumulated depreciation of $2,083 and $1,865 at respective dates	5,579		5,406
Total property, plant and equipment	32,069		30,184
Derivative assets	191		437
Restricted deposits	43		47
Rent payments in excess of levelized rent expense under plant operating leases	1,320		1,187
Regulatory assets	4,486		4,347
Other long-term assets	619		644
Total long-term assets	6,659		6,662
Total assets	$	47,672	$	45,530

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

3

Consolidated Balance Sheets	Edison International
(in millions, except share amounts, unaudited)	September 30, 2011			December 31, 2010
LIABILITIES AND EQUITY
Short-term debt	$	560		$	115
Current portion of long-term debt	51			48
Accounts payable	1,224			1,362
Accrued taxes	128			52
Accrued interest	207			205
Customer deposits	203			217
Derivative liabilities	290			217
Regulatory liabilities	734			738
Other current liabilities	764			998
Total current liabilities	4,161			3,952
Long-term debt	13,010			12,371
Deferred income taxes	6,003			5,625
Deferred investment tax credits	89			122
Customer advances	133			112
Derivative liabilities	344			468
Pensions and benefits	2,293			2,260
Asset retirement obligations	2,658			2,561
Regulatory liabilities	4,481			4,524
Other deferred credits and other long-term liabilities	2,454			2,041
Total deferred credits and other liabilities	18,455			17,713
Total liabilities	35,626			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)	2,346			2,331
Accumulated other comprehensive loss	(124		)	(76		)
Retained earnings	8,793			8,328
Total Edison International's common shareholders' equity	11,015			10,583
Preferred and preference stock of utility	1,029			907
Other noncontrolling interests	2			4
Total noncontrolling interests	1,031			911
Total equity	12,046			11,494
Total liabilities and equity	$	47,672		$	45,530

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

4

Consolidated Statements of Cash Flows	Edison International
	Nine months ended September 30,
(in millions, unaudited)	2011			2010
Cash flows from operating activities:
Net income	$	845		$	1,129
Less: Income (loss) from discontinued operations	(3		)	4
Income from continuing operations	848			1,125
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	1,288			1,127
Regulatory impacts of net nuclear decommissioning trust earnings	131			106
Other amortization	112			90
Stock-based compensation	22			20
Equity in income from unconsolidated affiliates – net	(68		)	(101		)
Distributions from unconsolidated entities	52			76
Deferred income taxes and investment tax credits	373			414
Proceeds from U.S. treasury grants	310			92
Income from leveraged leases	(4		)	(3		)
Changes in operating assets and liabilities:
Receivables	(205		)	(184		)
Inventory	(20		)	(27		)
Margin and collateral deposits – net of collateral received	6			32
Prepaid taxes	318			33
Other current assets	(319		)	(224		)
Rent payments in excess of levelized rent expense	(133		)	(148		)
Accounts payable	178			28
Accrued taxes	76			(23		)
Other current liabilities	(189		)	(129		)
Derivative assets and liabilities – net	137			1,079
Regulatory assets and liabilities – net	(73		)	(530		)
Other assets	(14		)	(40		)
Other liabilities	1			(67		)
Operating cash flows from discontinued operations	(3		)	4
Net cash provided by operating activities	2,824			2,750
Cash flows from financing activities:
Long-term debt issued	686			1,652
Long-term debt issuance costs	(24		)	(35		)
Long-term debt repaid	(97		)	(371		)
Bonds purchased	(86		)	—
Preference stock issued – net	123			—
Short-term debt financing – net	573			13
Settlements of stock-based compensation – net	(14		)	(7		)
Dividends and distributions to noncontrolling interests	(43		)	(39		)
Dividends paid	(313		)	(308		)
Net cash provided by financing activities	$	805		$	905

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

5

Consolidated Statements of Cash Flows	Edison International
	Nine months ended September 30,
(in millions, unaudited)	2011			2010
Cash flows from investing activities:
Capital expenditures	$	(3,491	)	$	(3,129	)
Purchase of interest in acquired companies	(3		)	(4		)
Proceeds from sale of nuclear decommissioning trust investments	2,108			903
Purchases of nuclear decommissioning trust investments and other	(2,254		)	(1,036		)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment	6			35
Investments in other assets	—			3
Effect of consolidation and deconsolidation of variable interest entities	—			(91		)
Net cash used by investing activities	(3,634		)	(3,319		)
Net increase (decrease) in cash and cash equivalents	(5		)	336
Cash and cash equivalents, beginning of period	1,389			1,673
Cash and cash equivalents, end of period	$	1,384		$	2,009

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 nine-month periods ended September 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 $1.1 billion at both September 30, 2011 and December 31, 2010. Generally, the carrying value of cash equivalents equals the fair value, as these 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 $215 million and $197 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at September 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)	September 30, 2011		December 31, 2010
Coal, gas, fuel oil and other raw materials	$	191	$	184
Spare parts, materials and supplies	401		384
Total inventory	$	592	$	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:

7

	Three months ended September 30,					Nine months ended September 30,
(in millions)	2011		2010			2011		2010
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	426	$	514		$	805	$	1,086
Participating securities dividends	—		(3		)	—		(5		)
Income from continuing operations available to common shareholders	$	426	$	511		$	805	$	1,081
Weighted average common shares outstanding	326		326			326		326
Basic earnings per share – continuing operations	$	1.31	$	1.57		$	2.47	$	3.32
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	426	$	511		$	805	$	1,081
Income impact of assumed conversions	1		2			3		3
Income from continuing operations available to common shareholders and assumed conversions	$	427	$	513		$	808	$	1,084
Weighted average common shares outstanding	326		326			326		326
Incremental shares from assumed conversions	3		2			3		2
Adjusted weighted average shares – diluted	329		328			329		328
Diluted earnings per share – continuing operations	$	1.30	$	1.57		$	2.46	$	3.30

Stock-based compensation awards to purchase 5,943,378 and 9,700,218 shares of common stock for the three months ended September 30, 2011 and 2010, respectively, and 8,970,290 and 6,154,826 shares of common stock for the nine months ended September 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

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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 nine months ended September 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 (loss)	—			—			802			802			(1		)	44			845
Other comprehensive loss	—			(48		)	—			(48		)	—			—			(48		)
Common stock dividends declared ($0.96 per share)	—			—			(313		)	(313		)	—			—			(313		)
Dividends, distributions to noncontrolling interests and other	—			—			—			—			(1		)	(44		)	(45		)
Stock-based compensation and other	7			—			(21		)	(14		)	—			—			(14		)
Noncash stock-based compensation and other	22			—			(3		)	19			—			(1		)	18
Purchase of noncontrolling interests1	(14		)	—			—			(14		)	—			—			(14		)
Issuance of preference stock	—			—			—			—			—			123			123
Balance at September 30, 2011	$	2,346		$	(124	)	$	8,793		$	11,015		$	2		$	1,029		$	12,046

¹  During the nine months ended September 30, 2011, EMG purchased the remaining interests in Pinnacle Wind Force, LLC, and Broken Bow I, LLC and all assets of the Crofton Bluffs project. All three projects are now 100% owned by EMG. The purchases of the noncontrolling interests were accounted for as equity transactions between controlling and noncontrolling interest holders.

The following table provides the changes in equity for the nine months ended September 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	—		—			1,090			1,090			—			39			1,129
Other comprehensive loss	—		(11		)	—			(11		)	—			—			(11		)
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 ($0.945 per share)	—		—			(308		)	(308		)	—			—			(308		)
Dividends, distributions to noncontrolling interests and other	—		—			—			—			(4		)	(39		)	(43		)
Stock-based compensation and other	5		—			(12		)	(7		)	—			—			(7		)
Noncash stock-based compensation and other	16		—			(2		)	14			—			—			14
Balance at September 30, 2010	$	2,325	$	26		$	8,283		$	10,634		$	5		$	907		$	11,546

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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 September 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)	September 30, 2011		December 31, 2010
Current assets	$	40	$	26
Net property, plant and equipment	702		739
Other long-term assets	6		6
Total assets	$	748	$	771
Current liabilities	$	28	$	25
Long-term debt net of current portion	67		71
Deferred revenues	69		71
Other long-term liabilities	21		21
Total liabilities	$	185	$	188
Noncontrolling interests	$	2	$	4

At September 30, 2011 and December 31, 2010, assets serving as collateral for the debt obligations had a carrying value of $160 million and $163 million, respectively, and primarily consist of property, plant and equipment.

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has 16 power purchase agreements ("PPAs") that have variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to fuel 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 September 30, 2011 and the amounts that SCE paid to these projects were $178 million and $205 million for the three months ended September 30, 2011 and 2010, respectively, and $347 million and

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$447 million for the nine months ended September 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 September 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.

EMG accounts for its interest in three renewable wind generating facilities under the equity method. At December 31, 2010, EMG had interests in 2 renewable wind generating facilities, the Elkhorn Ridge and San Juan Mesa projects. In addition to these 2 projects, at September 30, 2011, EMG had interests in Community Wind North, which achieved commercial operation on May 28, 2011. 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:

	September 30, 2011
(in millions)	Investment		Maximum Exposure
Natural gas-fired projects	$	340	$	340
Renewable energy projects	228		228

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 September 30, 2011, entities which EMG has accounted for under the equity method had indebtedness of $64 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 determine 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 September 30, 2011
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	1,056	$	—	$	—		$	—		$	1,056
Derivative contracts:
Electricity	—		43		213			(36		)	220
Natural gas	2		61		10			(6		)	67
Fuel oil	2		—		—			(2		)	—
Tolling	—		—		4			—			4
Coal	—		1		—			(1		)	—
Subtotal of commodity contracts	4		105		227			(45		)	291
Long-term disability plan	9		—		—			—			9
Nuclear decommissioning trusts:
Stocks3	1,721		—		—			—			1,721
Municipal bonds	—		767		—			—			767
U.S. government and agency securities	378		123		—			—			501
Corporate bonds4	—		318		—			—			318
Short-term investments, primarily cash equivalents5	2		151		—			—			153
Subtotal of nuclear decommissioning trusts	2,101		1,359		—			—			3,460
Total assets6	3,170		1,464		227			(45		)	4,816
Liabilities at Fair Value
Derivative contracts:
Electricity	—		17		84			(18		)	83
Natural gas	—		240		12			(12		)	240
Fuel oil	1		—		—			(1		)	—
Tolling	—		—		231			—			231
Subtotal of commodity contracts	1		257		327			(31		)	554
Interest rate contracts	—		80		—			—			80
Total liabilities	1		337		327			(31		)	634
Net assets (liabilities)	$	3,169	$	1,127	$	(100	)	$	(14	)	$	4,182

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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 69% and 67% of the equity investments were located in the United States at September 30, 2011 and December 31, 2010, respectively.

⁴  At September 30, 2011 and December 31, 2010, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $21 million and $27 million, respectively.

⁵  Excludes net liabilities of $67 million and $5 million at September 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 September 30, 2011 and December 31, 2010, 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 September 30,							Nine months ended September 30,
(in millions)	2011				2010			2011				2010
Fair value, net asset (liabilities) at beginning of period	$	(275	)		$	(703	)	$	97			$	62
Total realized/unrealized gains (losses):
Included in earnings1	(4		)		24			14				51
Included in regulatory assets and liabilities2	162			3	(142		)	(220		)	3	(924		)
Included in accumulated other comprehensive income	1				1			(2		)		5
Purchases	24				15			51				48
Settlements	(8		)		(76		)	(38		)		(128		)
Transfers in or out of Level 3	—				(12		)	(2		)		(7		)
Fair value, net liability at end of period	$	(100	)		$	(893	)	$	(100	)		$	(893	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period4	$	(110	)		$	(163	)	$	(425	)		$	(882	)

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  Includes the elimination of the fair value of derivatives with SCE's consolidated affiliates.

⁴  Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income was a loss of $3 million for the three months ended September 30, 2010, and gains of $7 million and $1 million for the nine months ended September 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

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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 September 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 value and fair value of long-term debt are:

	September 30, 2011				December 31, 2010
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current portion	$	13,061	$	13,500	$	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.

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 October 2011, SCE issued $150 million of floating rate first and refunding mortgage bonds due in 2014. The proceeds from these bonds were used to finance fuel inventories.

In May 2011 and September 2011, SCE purchased $56 million and $30 million, respectively, of its variable rate tax-exempt bonds.

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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 floating rate construction loans totaling $495 million that will convert to 10-year amortizing term loans by June 30, 2013, subject to meeting specified conditions, and also included $122 million of letter of credit ($40 million outstanding at September 30, 2011) and working capital facilities.

The non-recourse financings were completed in two parts. A construction plus term loan financing of $442 million that initially accrues interest at the London Interbank Offered Rate (LIBOR) plus 2.25% and increases by 0.25% after the third, sixth and ninth anniversaries of the term conversion date. An interest rate swap agreement for a portion of the construction loan fixed the floating rate at 0.81% beginning November 30, 2011 through March 31, 2013. The effective rate for the outstanding loan of $44 million was 2.48% at September 30, 2011. Under the swap agreement for majority of the term loan, the fixed interest rate will be 3.54% beginning June 28, 2013 through May 31, 2023 and the effective rate is expected to be 5.84%.

A second construction plus term loan financing of $53 million was obtained by a holding company that accrues interest at LIBOR plus 4.00% over the entire term. An interest rate swap agreement for a portion of the construction loan fixed the floating rate at 0.79% beginning July 29, 2011 through May 31, 2013. The effective rate for the outstanding loan of $49 million was 4.94% at September 30, 2011. Under the swap agreement for the majority of the term loan, the fixed interest rate will be 4.00% beginning June 28, 2013 through May 31, 2023 and the effective rate is expected to be 8.00%, Both outstanding loans were recorded in long-term debt on Edison International's consolidated balance sheet at September 30, 2011.

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 millionten-year term loan (expiring in December 2020), a $23 millionseven-year letter of credit facility and a $5 millionseven-year working capital facility. At September 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 September 30, 2011, SCE's outstanding short-term debt was $550 million at a weighted-average interest rate of 0.34%. 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 September 30, 2011, letters of credit issued under SCE's credit facilities aggregated $83 million and are scheduled to expire in twelve months or less.

At September 30, 2011, Edison International (Parent)'s outstanding short-term debt was $10 million at a weighted-average interest rate of 0.60%. 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 September 30, 2011, standby letters of credit under EME's credit facility aggregated $65 million and were scheduled to expire as follows: $1 million in 2011 and $64 million in 2012. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $98 million and were scheduled to expire as follows: $7 million in 2011, $63 million in 2012, $10 million in 2017, and $18 million in 2018.

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

16

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	September 30, 2011	December 31, 2010
Electricity options, swaps and forwards	GWh	30,143	32,138
Natural gas options, swaps and forwards	Bcf	266	250
CRRs	GWh	146,628	181,291
Tolling arrangements	GWh	104,822	114,599

Fair Value of Derivative Instruments

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

	Derivative Assets									Derivative Liabilities1
(in millions)	Short- Term			Long- Term			Subtotal			Short- Term			Long- Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	82		$	145		$	227		$	305		$	577		$	882		$	655
Netting and collateral	(14		)	(13		)	(27		)	(18		)	(23		)	(41		)	(14		)
Total	$	68		$	132		$	200		$	287		$	554		$	841		$	641

¹  Includes the fair value of derivatives with SCE's consolidated affiliates; however, in Edison International’s consolidated financial statements, the fair value of such derivatives is eliminated.

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 that such gains or losses will be part of the purchased power costs recovered from ratepayers. As a result, realized gains and losses are not reflected in earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore are also not reflected in earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.

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The following table summarizes the components of economic hedging activity:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Realized losses	$	(58	)	$	(53	)	$	(132	)	$	(116	)
Unrealized losses	(110		)	(165		)	(433		)	(1,022		)

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 $162 million and $67 million as of September 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 September 30, 2011, SCE would be required to post $23 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:

September 30, 2011
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges		Economic Hedges		Trading Activities
Electricity	Forwards/Futures	Sales	GWh	15,910	1	13,353	3	36,597
Electricity	Forwards/Futures	Purchases	GWh	101	1	13,230	3	42,429
Electricity	Capacity	Sales	MW-Day (in thousands)	134	2	—		12	2
Electricity	Capacity	Purchases	MW-Day (in thousands)	12	2	—		219	2
Electricity	Congestion	Sales	GWh	—		90	4	15,910	4
Electricity	Congestion	Purchases	GWh	—		4,023	4	253,688	4
Natural gas	Forwards/Futures	Sales	bcf	—		—		55.3
Natural gas	Forwards/Futures	Purchases	bcf	—		—		53.4
Fuel oil	Forwards/Futures	Sales	barrels	—		—		100,000
Fuel oil	Forwards/Futures	Purchases	barrels	—		240,000		140,000
Coal	Forwards/Futures	Sales	tons	—		—		1,485,000
Coal	Forwards/Futures	Purchases	tons	—		—		1,485,000

(in millions)
Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date
Accreting forward starting interest rate swap	Convert floating rate (1-month LIBOR debt to fixed rate (0.8135%) debt	Cash flow	$	39	May 2013
Accreting interest rate swap	Convert floating rate (1-month LIBOR debt to fixed rate (0.79%) debt	Cash flow	24		May 2013
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 forward starting interest rate swap	Convert floating rate (3-month LIBOR debt to fixed rate (3.5429%) debt	Cash flow	398		May 2023
Amortizing forward starting interest rate swap	Convert floating rate (3-month LIBOR debt to fixed rate (4.0025%) debt	Cash flow	48		May 2023
Amortizing interest rate swap	Convert floating rate (3-month LIBOR debt to fixed rate (4.29%) debt	Cash flow	119		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:

September 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	$	34		$	8		$	42		$	16		$	90		$	106		$	(64	)
Economic hedges	29			3			32			31			2			33			(1		)
Trading activities	132			102			234			96			37			133			101
	195			113			308			143			129			272			36
Netting and collateral received1	(163		)	(54		)	(217		)	(140		)	(49		)	(189		)	(28		)
Total	$	32		$	59		$	91		$	3		$	80		$	83		$	8

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 Nine Months Ended September 30,						Income Statement Location
(in millions)	2011			2010
Beginning of period derivative gains	$	27		$	175
Effective portion of changes in fair value	(62		)	102
Reclassification to net income	(29		)	(134		)	Competitive power generation revenue
End of period derivative gains (losses)	$	(64	)	$	143

¹  Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income (loss) at September 30, 2011 and 2010 were $(39) million and $86 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 of $4 million during each of the third quarters of 2011 and 2010, and $6 million and $5 million during the nine months ended September 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 September 30,					Nine months ended September 30,
(in millions)	Income Statement Location	2011			2010		2011		2010
Economic hedges	Competitive power generation revenue	$	(6	)	$	7	$	20	$	—
	Fuel	(3		)	2		1		—
Trading activities	Competitive power generation revenue	11			28		68		108

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. Future increases in power prices could expose EMG's subsidiaries to 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)	September 30, 2011		December 31, 2010
Collateral provided to counterparties:
Offset against derivative liabilities	$	16	$	8
Reflected in margin and collateral deposits	53		65
Collateral received from counterparties:
Offset against derivative assets	30		52

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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Income from continuing operations before income taxes	$	683		$	774		$	1,217		$	1,386
Provision for income tax at federal statutory rate of 35%	239			271			426			485
Increase (decrease) in income tax from:
Items presented with related state income tax, net:
Global Settlement related1	—			(37		)	—			(175		)
Change in tax accounting method for asset removal costs2	—			—			—			(40		)
State tax – net of federal benefit	30			34			43			57
Health care legislation3	—			—			—			39
Production and housing credits	(12		)	(14		)	(48		)	(48		)
Property-related and other	(15		)	(7		)	(52		)	(57		)
Total income tax expense from continuing operations	$	242		$	247		$	369		$	261
Effective tax rate	35		%	32		%	30		%	19		%

¹  During the nine months ended September 30, 2010, Edison International recognized a $175 million earnings benefit resulting from the

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Global Settlement, including $138 million in the second quarter resulting from the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service ("IRS") in 2009 and revision to interest recorded on the federal Global Settlement, and $37 million in the third quarter resulting from receipt of the final interest determination from the California Franchise Tax Board.

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 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	53			60
Tax positions taken during a prior year:
Increases	60			251
Decreases	(37		)	(86		)
Decreases for settlements during the period	—			(82		)
Balance at September 30,	$	641		$	807

As of September 30, 2011 and December 31, 2010, $500 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 $191 million, including interest and penalties through September 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 $92 million, including interest through September 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 $230 million and $213 million as of September 30, 2011 and December 31, 2010, respectively.

The net after-tax interest and penalties recognized in income tax expense was $5 million and $10 million for the three- and

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nine-month periods ended September 30, 2011, respectively, compared to a benefit of $7 million and $95 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 nine months ended September 30, 2011, Edison International made contributions of $113 million and during the remainder of 2011, expects to make $30 million of additional contributions. In 2011, annual contributions made to most of SCE's pension plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.

Expense components are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Service cost	$	43		$	34		$	129		$	102
Interest cost	52			54			156			162
Expected return on plan assets	(60		)	(52		)	(180		)	(156		)
Amortization of prior service cost	2			2			6			6
Amortization of net loss	6			7			18			21
Expense under accounting standards	43			45			129			135
Regulatory adjustment – deferred	(6		)	(14		)	(18		)	(42		)
Total expense recognized	$	37		$	31		$	111		$	93

Postretirement Benefits Other Than Pensions

During the nine months ended September 30, 2011, Edison International made contributions of $18 million and during the remainder of 2011, expects to make $38 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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Service cost	$	11		$	8		$	33		$	24
Interest cost	33			31			99			93
Expected return on plan assets	(28		)	(25		)	(84		)	(75		)
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss	9			8			27			24
Total expense	$	16		$	13		$	48		$	39

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Stock-Based Compensation

During 2011, Edison International granted 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	3,394,229		37.95
Expired	(113,348	)	48.52
Forfeited	(369,267	)	33.03
Exercised	(1,557,548	)	26.22
Outstanding at September 30, 2011	20,496,275		34.51		6.07
Vested and expected to vest at September 30, 2011	20,021,144		34.53		6.02	$	123
Exercisable at September 30, 2011	12,043,993		34.93		4.52	84

At September 30, 2011, there was $23 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	153,067		30.19		153,067
Forfeited1	(119,835	)	42.64		(119,835	)
Nonvested at September 30, 2011	448,260		27.96		448,260		23.26

¹ Includes performance shares that expired with zero value as performance targets were not met.

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 September 30, 2011, there was $5 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	251,890		37.95
Forfeited	(27,114	)	32.05
Paid Out	(133,958	)	47.60
Nonvested at September 30, 2011	735,614		$	32.15

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At September 30, 2011, there was $10 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $2 million in 2011, $5 million in 2012 and $3 million in 2013.

Supplemental Data on Stock Based Compensation

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2011		2010		2011		2010
Stock based compensation expense1	$	8	$	9	$	25	$	26
Income tax benefits related to stock compensation expense	3		3		10		10
Excess tax benefits2	3		3		7		5
Stock options
Cash used to purchase shares to settle options	20		17		59		30
Cash from participants to exercise stock options	16		10		41		19
Value of options exercised	4		7		18		11
Restricted stock units
Value of shares settled	1		—		6		—
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.

Note 9. Commitments and Contingencies

Third-Party Power Purchase Agreements

During the nine months ended September 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: $116 million each year in 2012 – 2015 and $1.9 billion for the period remaining thereafter.

In October 2011, SCE completed its 2011 annual request for offers and entered into new power purchase contracts with commitments estimated to be: $5 million in 2012, $81 million in 2013, $178 million in 2014 and $240 million in 2015.

Other Commitments

Firm Transmission Commitments

During the nine months ended September 30, 2011, SCE had a firm transmission agreement with additional commitments estimated to be: $1 million in 2011, $4 million each year in 2012 – 2015 and $78 million for the period remaining thereafter.

Fuel Supply Contracts and Coal Transportation Agreements

At September 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, together with estimated transportation costs under existing agreements, are estimated to aggregate $925 million, which consists of: $245 million for the remainder of 2011, $332 million in 2012, $198 million in 2013 and $150 million in 2014.

Turbine Commitments

Based upon a June 2011 contract amendment, EMG was required to schedule turbine deliveries by September 2011 or incur a termination obligation equal to its turbine deposit of $29 million. Under the terms of a September 2011 contract amendment, EMG scheduled turbine deliveries for the Broken Bow I wind project which will utilize the $29 million turbine deposit. In October 2011, EMG entered into a contractual agreement for the purchase of additional turbines with commitments of $39 million through 2012 for the Crofton Bluffs wind 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)

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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, which commenced on October 8, 2010, if it has not elected to deploy the additional turbines and if certain other criteria apply.

Capital Commitments

At September 30, 2011, EMG's subsidiaries had firm commitments to spend approximately $157 million during the remainder of 2011, $235 million in 2012 and $19 million in 2013 for capital expenditures. These expenditures primarily relate to the Walnut Creek project 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 230 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at September 30, 2011. Midwest Generation had recorded a liability of $55 million at September 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

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liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. At September 30, 2011, EME had recorded a liability of $43 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. Under these tax indemnity agreements, the lessees in the sale-leaseback transactions agreed to indemnify the lessors for specified adverse tax consequences that could result from certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. Although the Collins Station lease terminated in April 2004, Midwest Generation's indemnities in favor of its former lease equity investors are still in effect. EME provided similar indemnities in the sale-leaseback transactions related to the Powerton and Joliet Stations in Illinois. 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.

EME agreed to indemnify the lessors in the sale-leaseback transaction related to the Homer City plant for certain negative federal income tax consequences should the rent payments be “levelized” for tax purposes and for potential foreign tax credit losses in the event that the lessor's debt is characterized as recourse, rather than non-recourse. This indemnity covers a limited range of possible tax consequences that are unrelated to performance under the lease.

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.

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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. A motion filed by the plaintiffs requesting that the dismissals be certified as “partial final judgments” capable of appeal, and requesting that the remaining claims be stayed pending such an appeal, is pending.

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 sought to have their suits certified as a class action and requested injunctive relief, as well as compensatory and punitive damages. In October 2011, the complaints were dismissed for lack of federal jurisdiction. EME does not know whether the plaintiffs will appeal the dismissal or file a complaint in state court.

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 alleged 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 called for an injunction ordering Homer City to install controls sufficient to meet BACT emission rates at all units subject to the complaint and for other remedies. The Pennsylvania Department of Environmental Protection, the State of New York and the State of New Jersey 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 sought to have their suit certified as a class action and requested injunctive relief, the funding of a health assessment study and medical monitoring, as well as compensatory and punitive damages.

On October 12, 2011, all of the claims in the US EPA's lawsuit were dismissed with prejudice. On October 13, 2011, the claims in the purported class action lawsuit that were based on the federal CAA were dismissed with prejudice, while state law statutory and common law claims were dismissed without prejudice to re-file in state court should the plaintiffs choose to do so. EME does not know whether the US EPA and the other plaintiffs in these cases will appeal the dismissal of these cases, or whether plaintiffs in the purported class action lawsuit will file a complaint in state court. If the plaintiffs are able to revive the

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lawsuits, 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.

Four Corners New Source Review Litigation

In October 2011, four private environmental organizations filed a CAA citizens' lawsuit against the co-owners of Four Corners. The complaint alleges that certain work performed at the Four Corners generating units 4 and 5, over the approximate periods of 1985-1986 and 2007-present, constituted plant “major modifications” for which the plant should have, but did not, obtain permits and install BACT in violation of the PSD requirements and of the New Source Performance Standards of the CAA. The complaint also alleges subsequent and continuing violation of BACT air emissions limits. The lawsuit seeks injunctive and declaratory relief, civil penalties, including a mitigation project and litigation costs. In November 2010, SCE entered into an agreement to sell its ownership interest in generating units 4 and 5 to APS. The sale is subject to regulatory approvals and is expected to close in late 2012. Under the agreement SCE would remain responsible for its pro rata share of certain environmental liabilities, including penalties arising from environmental violations prior to the sale, but SCE would not be liable for any costs of installing BACT or other costs related to continuing or extending Four Corners operations. SCE cannot predict the outcome of these matters or estimate the impact on its financial statements.

Concurrently, the US EPA has proposed a regional haze federal implementation plan based on an APS proposal that would require shut down of units 1, 2 and 3 by 2016 and the installation of selective catalytic reduction technology on units 4 and 5 by 2018. APS' proposal contemplated that these actions would both satisfy the federal regional haze requirements and resolve any New Source Review claims the US EPA might have. A final federal implementation plan is expected in early 2012.

Malibu Fire Order Instituting Investigation ("OII")

Following a 2007 wildfire in Malibu, California, the CPUC issued an OII to determine if any statutes, CPUC general orders, rules or regulations were violated by SCE or telecomm providers (“OII Respondents”) that shared the use of three failed power poles in the wildfire area. The CPUC's Consumer Protection and Safety Division (“CPSD”) has alleged, among other things, that the poles were overloaded, that the OII Respondents violated the CPUC's rules governing the design, construction and inspection of poles and misled the CPUC during its investigation of the fire, and that SCE failed to preserve evidence relevant to the investigation. In October 2011, the CPSD proposed that the OII Respondents be assessed penalties of approximately $99 million, with SCE being allocated approximately $50 million of the total. SCE has denied the allegations and believes the proposed penalties are excessive. CPSD's allegations will likely be set for hearing in the first quarter of 2012. SCE cannot predict the amount, if any, of penalties that the CPUC may ultimately impose on SCE.

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. Pursuant to the settlement, the Navajo Nation lawsuit was dismissed. The settlement agreement reached with the Navajo Nation did not have a material impact on SCE's financial statements.

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 September 30, 2011, Edison International's recorded estimated minimum liability to remediate its 27 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 (3 sites primarily related to Midwest Generation) was $60 million, of which $51 million was related to SCE, including $15 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

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identified material sites and immaterial sites could exceed its recorded liability by up to $195 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 $18 million of its recorded liability. SCE has recorded a regulatory asset of $50 million at September 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 $7 million to $17 million. Costs incurred for the nine months ended September 30, 2011 and 2010, were $9 million and $7 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 DOE's appeal of the decision was denied in August 2011. Additional legal action would be necessary to recover damages incurred after December 31, 2005. Any damages recovered are subject to CPUC review as to what amounts 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 the Cross-State Air Pollution Rule ("CSAPR"). CSAPR is the final form of a previously proposed replacement for the Clean Air Interstate Rule ("CAIR"), originally called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual sulfur dioxide ("SO₂") emissions and annual and ozone season nitrogen oxide ("NOx") 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 NOx emissions from operations will need to be matched by a sufficient amount of SO₂ or NOx 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 NOx allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual or seasonal compliance period, units must surrender allowances for each ton of SO₂ and NOx emitted or face penalties. While trading of allowances is permitted within designated groups of states, the rule provides for penalties against a unit with emissions in excess of its predefined "assurance level," but only if the state in which it is located also exceeds its budgeted emissions level. On October 6, 2011, the US EPA announced a proposed revision to the rule that would effectively eliminate such penalties in the first phase.

EMG believes that Midwest Generation's current environmental remediation plan developed to comply with the CPS, along with the allowances allocated to it under CSAPR, will be sufficient to comply with the requirements of CSAPR and the US EPA's proposed regulation on hazardous air pollutant emissions. In order to achieve compliance, Midwest Generation has begun work to install SO₂ controls at certain of its plants.

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 Homer City will be able to acquire allowances for 2012 and 2013 in sufficient quantity to cover its normal operations and whether it will be able to pass through the cost of such allowances in the marketplace. Also, Homer City's SO₂ emissions could exceed its assurance level, and, therefore, unless the proposed revision to the rule is adopted, Homer City could be subject to penalties depending on whether, collectively, emissions from all of the subject electrical generating facilities in Pennsylvania exceed the state's budgeted emissions level. Accordingly, Homer City is evaluating alternative options, including reduced dispatch and fuel modifications, for complying with Phase I of CSAPR. The cost of allowances, together with possible operational impacts or reductions of output that 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, including some expenditures 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. An application for a construction permit to install the additional controls was filed on October 3, 2011 with the Pennsylvania Department of Environmental Protection.

Homer City does not currently have sufficient capital and does not expect to generate sufficient funds from operations to complete such retrofits and will have to seek third-party financing, which will be subject to decisions by Homer City's lessors, holders of bonds who provided financing for the sale-leaseback transaction 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.

In July 2011, EME asked the US EPA to stay the effectiveness of CSAPR pending judicial review, and in October 2011, Homer

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City asked the US EPA to reconsider the rule. In August 2011, Homer City asked the United States Court of Appeals for the District of Columbia to review CSAPR and requested a stay of the rule while its motion is pending. Numerous similar challenges have been filed by other industry participants and by several states.

Proposed Hazardous Air Pollutant Regulations

In March 2011, the US EPA 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 December 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.

Ozone and Particulates

In September 2011, President Obama announced that the proposed revision to the National Ambient Air Quality Standards ("NAAQS") for ozone, which was expected to have set a more stringent standard for primary ozone and a distinct secondary standard to protect sensitive vegetation and ecosystems, was being withdrawn. The ozone NAAQS established in 2008 remains in place, but the implementation process must be completed before the 0.075 parts-per-million standard can be enforced. The US EPA has indicated that it intends to issue initial area designations of attainment, nonattainment, and unclassifiable areas across the nation in 2012. States will then be required develop and submit state implementation plans outlining how compliance with the 2008 NAAQS will be achieved. New primary and secondary ozone standards are expected in 2014.

Water Quality

Once-Through Cooling Issues

In March 2011, the US EPA 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 California utilities to procure 33% of their electricity requirements from renewable resources, as defined in the statute. The impact of the new 33% law will depend on how the CPUC and CEC implement 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 case brought by the Alaskan Native Village of Kivalina against Edison International and other defendants, the

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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 stay of the appeal has now been lifted and argument before the Ninth Circuit is scheduled for November 2011. Kivalina is seeking damages of up to $400 million for the cost of relocating the village.

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. Edison International was dismissed as a defendant in this complaint in July 2011, but SCE and EME remain defendants.

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	(55		)	7			—			(48		)
Balance at September 30, 2011	$	(39	)	$	(80	)	$	(5	)	$	(124	)

Included in accumulated other comprehensive loss at September 30, 2011 was $10 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $49 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 $11 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:

	Nine months ended September 30,
(in millions)	2011			2010
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	529		$	486
Tax payments (refunds) – net	(330		)	44
Noncash investing and financing activities:
Accrued capital expenditures	$	393		$	421
Details of debt exchange:
Pollution-control bonds redeemed	$	(86	)	$	(303	)
Pollution-control bonds issued	86			303
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	12			9

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)	September 30, 2011		December 31, 2010
Current:
Regulatory balancing accounts	$	191	$	213
Energy derivatives	262		162
Other	1		3
Total Current	454		378
Long-term:
Deferred income taxes – net	1,938		1,855
Pensions and other postretirement benefits	1,084		1,097
Unamortized generation investment – net	323		355
Unamortized loss on reacquired debt	253		268
Energy derivatives	214		177
Nuclear-related investment – net	160		154
Unamortized transmission and distribution investment – net	153		105
Regulatory balancing accounts	62		56
Other	299		280
Total Long-term	4,486		4,347
Total Regulatory Assets	$	4,940	$	4,725

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	September 30, 2011		December 31, 2010
Current:
Regulatory balancing accounts	$	728	$	733
Other	6		5
Total Current	734		738
Long-term:
Costs of removal	2,663		2,623
Asset Retirement Obligations	944		1,099
Regulatory balancing accounts	873		802
Other	1		—
Total Long-term	4,481		4,524
Total Regulatory Liabilities	$	5,215	$	5,262

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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	September 30, 2011		December 31, 2010		September 30, 2011		December 31, 2010
Stocks	—	$	861	$	895	$	1,721	$	2,029
Municipal bonds	2051	644		706		767		790
U.S. government and agency securities	2041	445		270		501		288
Corporate bonds	2054	266		288		318		346
Short-term investments and receivables/payables	One-year	81		26		86		27
Total		$	2,297	$	2,185	$	3,393	$	3,480

Trust fund earnings (based on specific identification) increase the trust fund balance and the asset retirement obligations ("ARO") regulatory liability. Proceeds from sales of securities (which are reinvested) were $962 million and $302 million for the three months ended September 30, 2011 and 2010, respectively, and $2.1 billion and $903 million for the nine months ended September 30, 2011 and 2010, respectively. Unrealized holding gains, net of losses, were $1.1 billion and $1.3 billion at September 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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Balance at beginning of period	$	3,657		$	3,083		$	3,480		$	3,140
Realized gains – net	41			14			76			48
Unrealized gains (losses) – net	(305		)	233			(199		)	90
Other-than-temporary impairments	(22		)	(5		)	(35		)	(16		)
Interest, dividends, contributions and other	22			22			71			85
Balance at end of period	$	3,393		$	3,347		$	3,393		$	3,347

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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Note 16. Other Income and Expenses

Other income and expenses are as follows:

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2011		2010		2011		2010
Other income:
Equity Available Funds Used During Construction	$	18	$	24	$	74	$	76
Increase in cash surrender value of life insurance policies	6		7		19		19
Other	2		2		10		8
Total utility other income	26		33		103		103
Competitive power generation and other income	1		—		7		—
Total other income	$	27	$	33	$	110	$	103
Other expenses:
Civic, political and related activities and donations	$	6	$	7	$	21	$	21
Other	4		3		14		18
Total utility other expenses	10		10		35		39
Competitive power generation and other expenses	1		2		2		—
Total other expenses	$	11	$	12	$	37	$	39

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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Operating Revenue:
Electric utility	$	3,386		$	3,098		$	8,063		$	7,504
Competitive power generation	596			691			1,686			1,838
Parent and other2	(1		)	(1		)	(3		)	(2		)
Consolidated Edison International	$	3,981		$	3,788		$	9,746		$	9,340
Net Income (Loss) attributable to Edison International:
Electric utility	$	406		$	394		$	838		$	858
Competitive power generation1	33			110			(17		)	214
Parent and other2	(13		)	6			(19		)	18
Consolidated Edison International	$	426		$	510		$	802		$	1,090

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Segment balance sheet information was:

(in millions)	September 30, 2011			December 31, 2010
Total Assets:
Electric utility	$	38,122		$	35,906
Competitive power generation	9,881			9,597
Parent and other2	(331		)	27
Consolidated Edison International	$	47,672		$	45,530

¹ Includes earnings (losses) from discontinued operations of none and $(4) million for the three months ended September 30, 2011 and 2010, respectively, and $(3) million and $4 million for the nine months ended September 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;

• 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;

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• 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 nine-month periods ended September 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 nine-month periods ended September 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 September 30,									Nine months ended September 30,
(in millions)	2011			2010			Change			2011			2010			Change
Net Income (Loss) attributable to Edison International
SCE	$	406		$	394		$	12		$	838		$	858		$	(20	)
EMG	33			110			(77		)	(17		)	214			(231		)
Edison International Parent and Other	(13		)	6			(19		)	(19		)	18			(37		)
Edison International Consolidated	426			510			(84		)	802			1,090			(288		)
Less: Non-Core Items
Global Settlement:
SCE	—			42			(42		)	—			95			(95		)
EMG	—			(6		)	6			—			52			(52		)
Edison International Parent and Other	—			1			(1		)	—			28			(28		)
SCE – tax impact of health care legislation	—			—			—			—			(39		)	39
EMG discontinued operations	—			(4		)	4			(3		)	4			(7		)
Total non-core items	—			33			(33		)	(3		)	140			(143		)
Core Earnings (Losses)
SCE	406			352			54			838			802			36
EMG	33			120			(87		)	(14		)	158			(172		)
Edison International Parent and Other	(13		)	5			(18		)	(19		)	(10		)	(9		)
Edison International Consolidated	$	426		$	477		$	(51	)	$	805		$	950		$	(145	)

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 (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as earnings attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including lease terminations, sale of certain assets, early debt extinguishment costs and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings.

SCE's 2011 core earnings increased $54 million and $36 million for the quarter and year-to-date, respectively. Core earnings in both periods increased due to rate base growth. The quarterly core earnings increase was also attributable to lower income taxes. The year-to-date increase was partially 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. In October 2011, the CPUC authorized SCE to recover legal costs incurred between 2004 and 2009 in support of SCE's efforts to obtain generator refunds. As a result, SCE expects to record revenue of approximately $25 million in the fourth quarter of 2011.

EMG's 2011 core earnings decreased $87 million and $172 million for the quarter and the year-to-date, respectively. The decrease in core earnings during the quarter was due to lower capacity revenues, realized energy prices and generation from merchant coal plants, and lower trading income and capacity factors from renewable projects. The decrease in core earnings during the quarter was also due to a gain in 2010 from the sale of bankruptcy claims. The decrease in year-to-date core earnings was due to lower realized energy prices and generation from merchant coal plants, higher plant maintenance costs from outages, higher interest expense related to renewable projects, and lower trading income. In addition, unrealized losses were $4 million for the nine months of 2011 compared to unrealized losses of $30 million in the same period last year.

Edison International Parent and Other 2011 core earnings decreased $18 million and $9 million for the quarter and the

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year-to-date, respectively, primarily due to lower tax benefits in 2011 compared to 2010.

Consolidated non-core items for Edison International included:

• An earnings benefit of $175 million recorded in 2010 relating to the California impact of the federal Global Settlement, including $138 million in the second quarter resulting from acceptance by the Franchise Tax Board of the tax positions finalized with the IRS in 2009 and $37 million in the third quarter resulting from receipt of the final interest determination from the Franchise Tax Board.

• 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 nine 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 $2.5 billion during the first nine months of 2011 compared to $2.4 billion during the same period in 2010.

As discussed under "Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2010 MD&A, SCE continues to project that 2011 capital expenditures will be in the range of $3.9 billion to $4.4 billion and that 2011 - 2014 total capital expenditures will be in the range of $15.6 billion to $17.5 billion. Actual capital spending will be affected by: changes in regulatory, environmental and engineering design requirements; permitting and project delays; cost and availability of labor, equipment and materials; and other factors.

SCE is currently completing the final engineering design for the Tehachapi Transmission Project and anticipates an increase in its 2011-2014 expenditures for the project as a result of cost pressures associated with engineering design and scope changes, environmental mitigation work, and regulatory and permit delays. The project may be further impacted by the CPUC's response to SCE's petition to modify the 2009 decision approving the project for the purpose of obtaining authorization to install aviation marking and lighting. In October 2011, the CPUC staff notified SCE that the constructed portions of the project could be marked and lighted as required, but instructed SCE to defer completion of remaining project components that may require aviation marking or lighting pending CPUC review of the petition to modify. Community opposition to portions of the project continues and requests for reconsideration of the CPUC's 2009 decision are pending. Once final engineering is complete, SCE will file a revised cost estimate with the CPUC. As with all transmission investments, cost recovery will be subject to future rate proceedings.

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 the 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. SCE does not expect these projects to be re-evaluated. 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 October 2011, SCE submitted updated testimony to reflect changes in escalation rates, known changes due to governmental actions and changes in the timing of recovery for nuclear outages, which taken together changed its requested 2012 base rate revenue requirement to $6.3 billion. SCE's updated request, after considering the effects of sales growth, would result in incremental customer base rate increases of $824 million, $136 million and $532 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

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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, but the Administrative Law Judge

handling the GRC has indicated that a final decision is not expected before year-end. To the extent that a final decision is delayed beyond the end of 2011, 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 or the timing of the final 2012 GRC decision.

FERC Formula Rates

In August 2011, the FERC accepted, subject to refund and settlement procedures, 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") revenue requirement that was previously recovered through a separate mechanism. The FERC reduced SCE's proposed base ROE request from 11.5% to 9.93%. SCE estimates its total 2012 FERC weighted average ROE will be 11.1%, including the previously authorized 50 basis point incentive for CAISO participation and individual authorized project incentives. The actual weighted average ROE is dependent upon the amount and timing of capital expenditures among FERC incentive and non-incentive projects. 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 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. SCE and the other parties to the proceeding are currently in settlement negotiations. SCE does not expect a final decision until 2012 and cannot predict the formula rate structure that the FERC will ultimately authorize.

In September 2011, SCE reduced its forecasted 2012 transmission revenue requirement for the lower ROE by $49 million to $722 million. SCE had requested a rehearing of the adopted base ROE, however the FERC denied such request in October 2011. SCE is evaluating and must decide by December 2011 whether to appeal the FERC order at the DC Circuit Court. Separately, in October 2011, the FERC issued an order denying SCE's request for rehearing of its 2008 and 2011 CWIP proceedings which adopted a base ROE of 9.54% and 10.3%, respectively, compared to SCE's request of 11.5%. The reduced ROE in these proceedings did not have a material impact on SCE's financial statements.

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's Near Term Task Force ("NTTF") conducted 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 NTTF 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 NTTF Report proposed changes to regulations applicable to protection against natural phenomena, including earthquakes and flooding and emergency preparedness, and the NTTF made a number of recommendations as to actions that the NRC might implement. The timing and prioritization of these recommendations must be voted on by the NRC and the nuclear industry will have an opportunity to comment on the timing and scope of these recommendations prior to their implementation. If implemented, the recommendations 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 at the Midwest Generation plants, higher fuel costs and outages at the Homer City plant. In addition, the profitability of EMG's Midwest Generation plants is expected to be adversely affected by a decline in capacity prices 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 may 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 September 30, 2011, EMG and its subsidiaries had $1.3 billion in cash and cash equivalents and $1.0 billion of liquidity

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available from credit facilities that expire in 2012. EMG's principal subsidiary, EME, had $3.7 billion of senior notes outstanding at September 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 the CSAPR . CSAPR is the final form of a previously proposed replacement for the CAIR, originally called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual SO₂ emissions and annual and ozone season NOx 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 SO₂emissions.

CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. Under CSAPR, the amount of actual SO₂or NOx emissions from operations will need to be matched by a sufficient amount of SO₂or NOx 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 NOx allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual or seasonal compliance period, units must surrender allowances for each ton of SO₂ and NOx emitted or face penalties. While trading of allowances is permitted within designated groups of states, the rule provides for penalties against a unit with emissions in excess of its predefined "assurance level," but only if the state in which it is located also exceeds its budgeted emissions level. On October 6, 2011, the US EPA announced a proposed revision to the rule that would effectively eliminate such penalties in the first phase.

EMG believes that Midwest Generation's current environmental remediation plan developed to comply with the CPS, along with the allowances allocated to it under CSAPR, will be sufficient to comply with the requirements of CSAPR and the US EPA's proposed regulation on hazardous air pollutant ("HAP") emissions. In order to achieve compliance, Midwest Generation has begun work to install SO₂ controls at certain of its plants.

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 SO₂emissions 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 Homer City will be able to acquire allowances for 2012 and 2013 in sufficient quantity to cover its normal operations and whether it will be able to pass through the cost of such allowances in the marketplace. Also, Homer City's SO₂ emissions could exceed its assurance level, and, therefore, unless the US EPA's proposed revision to the rule is adopted, Homer City could be subject to penalties depending on whether, collectively, emissions from all of the subject electrical generating facilities in Pennsylvania exceed the state's budgeted emissions level. Accordingly, Homer City is evaluating alternative options, including reduced dispatch and fuel modifications, for complying with Phase I of CSAPR. The cost of allowances, together with possible operational impacts or reductions of output that 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 SO₂and 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 SO₂controls will require capital commitments for the Homer City plant well in advance of the 2014 effective date, including some expenditures 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 SO₂and 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. An application for a construction permit to install the additional controls was filed on October 3, 2011 with the Pennsylvania Department of Environmental Protection.

Homer City Capital Needs and Liquidity

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, and has chosen not to, provide funding. Homer City expects to fund $13 million of project costs during the remainder of 2011. However, Homer City will need third-party capital to undertake the retrofits required by 2014 under CSAPR and to fund capital costs beginning in 2012 in order to complete the requisite retrofits by early 2014. However, restrictions under the agreements entered into as part of

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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, Homer City's ability to install environmental compliance equipment will be dependent on approvals by its lessors and holders of bonds who provided financing for the sale-leaseback transaction, and its ability to obtain new capital funding.

Homer City has engaged a financial advisor and commenced a process to obtain capital funding from third parties to install the environmental improvements. Homer City's objective is to maximize the value of its leasehold interest while obtaining the incremental capital needed to make such improvements. 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. A significant dilution of interest in the Homer City plant may result in a financial statement deconsolidation of Homer City if EME no longer retains control for inclusion in the consolidated financial statements. In this event, the transaction would be accounted for as a disposition and could result in a material loss. At September 30, 2011, the book value of EME's investment in Homer City and related assets was approximately $1.1 billion.

Homer City believes that the persistence of low power prices, combined with the outages suffered earlier this year and the possible impacts of compliance with CSAPR Phase I in 2012, will make it unlikely that Homer City will meet the covenant requirements of its sale-leaseback documents relating to the payment of equity rent at April 1, 2012. Under the sale-leaseback 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 must 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). A failure to pay equity rent does not entitle the owner-lessors to foreclose upon Homer City's leasehold interest, but it does result in the suspension of Homer City's ability to make permitted distributions. Moreover, the ability to make permitted distributions would be permanently frozen if a failure to pay equity rent when due was not cured within nine months, or even if timely cured, there occurred more than one additional failure to pay equity rent when due at any future time during the term of the lease. 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. Also, failure by Homer City to pay equity rent when due in April 2012 could trigger termination of the $47 million senior rent reserve letter of credit. Homer City would then be required to fund the senior rent reserve, and failure to do so could entitle counterparties to seek available remedies under the sale-leaseback documents, including termination or foreclosure upon the leasehold interest.

EME's subsidiary, EMMT, enters into energy and capacity transactions on behalf of Homer City pursuant to an intercompany agreement. Those transactions are generally back-to-back transactions in which EMMT enters into a transaction with a third party as a principal and then enters into an equivalent transaction with Homer City. In the case of energy sales, if Homer City fails to perform its obligations under the intercompany agreement, EMMT would seek to fulfill its third-party obligations through market transactions which may result in losses. In the case of capacity, EMMT has sold Homer City capacity in the annual PJM base residual auctions through May 2015. If Homer City were to default on its obligations to supply capacity, then EMMT would be liable to PJM to supply that capacity, and failure to do so would expose EMMT to penalties under the PJM tariffs. If one or more of the Homer City units were to be unavailable as a capacity resource and EMMT did not fulfill this obligation through market transactions, then PJM would assess a penalty against EMMT (excluding a refund of any capacity payments received by EMMT) equal to the greater of 20% of the capacity payments or $20 per MW-day.

Failure of Homer City to find an economic manner to continue plant operations, by installing the required equipment or otherwise, could result in a foreclosure on its leasehold interest and/or a curtailment of plant operations. These events or other matters described above could have an adverse effect on future financial results, cash flow, financial flexibility and assets of EME compared to historical levels.

Midwest Generation Environmental Compliance Plans and Costs

During 2011, Midwest Generation continued its permitting and planning activities for NOx 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's 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 NOx and SO₂as 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.

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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.

Decisions regarding whether or not to proceed with retrofitting units to comply with CPS requirements for SO₂emissions, including those that have received permits, 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 or continue with the expenditure of 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. Pending such final decisions, Midwest Generation plans to continue with any work necessary to comply with issued permits.

Environmental Regulation Developments

For additional discussion of environmental regulation developments regarding the Cross-State Air Pollution Rule, proposed Hazardous Air Pollutant Regulations, Ozone and Particulates Standards, 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 and FERC-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 September 30, 2011 versus September 30, 2010

	Three months ended September 30, 2011								Three months ended September 30, 2010
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated
Operating revenue	$	1,697		$	1,689	$	3,386		$	1,601		$	1,497	$	3,098
Fuel and purchased power	—			1,374		1,374			—			1,218		1,218
Operations and maintenance	541			278		819			541			262		803
Depreciation, decommissioning and amortization	323			35		358			300			16		316
Property taxes and other	69			2		71			64			1		65
Total operating expenses	933			1,689		2,622			905			1,497		2,402
Operating income	764			—		764			696			—		696
Net interest expense and other	(98		)	—		(98		)	(84		)	—		(84		)
Income before income taxes	666			—		666			612			—		612
Income tax expense	245			—		245			205			—		205
Net income	421			—		421			407			—		407
Dividends on preferred and preference stock	15			—		15			13			—		13
Net income available for common stock	$	406		$	—	$	406		$	394		$	—	$	394
Core Earnings1						$	406							$	352
Non-Core Earnings:
Global Settlement						—								42
Total SCE GAAP Earnings						$	406							$	394

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

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Utility Earning Activities

Utility earning activities were primarily affected by the following:

• Higher operating revenue of $96 million primarily due to the following:

• $50 million increase primarily due to a 4.35% increase in 2011 authorized revenue approved in the 2009 CPUC 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 primarily related to the steam generator replacement project and EdisonSmartConnect^TM.

• Higher depreciation, decommissioning and amortization expense of $23 million primarily related to increased transmission and distribution investments.

• 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 benefit recorded in 2010 related to the Global Settlement. 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 $146 million primarily driven by the cost to replace CDWR contracts that expired in 2011 .

• Higher operation and maintenance expense of $16 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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Nine Months Ended September 30, 2011 versus September 30, 2010

	Nine months ended September 30, 2011								Nine months ended September 30, 2010
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated
Operating revenue	$	4,442		$	3,621	$	8,063		$	4,175		$	3,329		$	7,504
Fuel and purchased power	—			2,691		2,691			—			2,612			2,612
Operations and maintenance	1,619			831		2,450			1,598			674			2,272
Depreciation, decommissioning and amortization	964			94		1,058			905			40			945
Property taxes and other	212			5		217			193			2			195
Gain on sale of assets	—			—		—			—			(1		)	(1		)
Total operating expenses	2,795			3,621		6,416			2,696			3,327			6,023
Operating income	1,647			—		1,647			1,479			2			1,481
Net interest expense and other	(269		)	—		(269		)	(244		)	(2		)	(246		)
Income before income taxes	1,378			—		1,378			1,235			—			1,235
Income tax expense	496			—		496			338			—			338
Net income	882			—		882			897			—			897
Dividends on preferred and preference stock	44			—		44			39			—			39
Net income available for common stock	$	838		$	—	$	838		$	858		$	—		$	858
Core Earnings1						$	838								$	802
Non-Core Earnings:
Global Settlement						—									95
Tax impact of health care legislation						—									(39		)
Total SCE GAAP Earnings						$	838								$	858

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 $267 million primarily due to the following:

• $130 million increase primarily due to a 4.35% increase in 2011 authorized revenue approved in the 2009 CPUC GRC decision.

• $90 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.

• $50 million increase related to capital-related revenue requirements primarily related to the steam generator replacement project and EdisonSmartConnect^TM.

• Higher depreciation, decommissioning and amortization expense of $59 million primarily related to increased transmission and distribution investments.

• Higher net interest expense and other of $25 million primarily due to higher outstanding balances on long-term debt.

• Higher income taxes primarily due to benefits recorded in 2010 related to the Global Settlement. See "—Income Taxes" below for more information.

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Utility Cost-Recovery Activities

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

• Higher purchased power expense of $85 million primarily driven by the cost to replace CDWR contracts that expired in 2011 and higher average prices from a shift to renewable contracts. The increase was partially offset by increased purchased power in 2010 during the outages at San Onofre and Four Corners.

• Higher operation and maintenance expense of $157 million resulting primarily from increased energy efficiency program costs.

• Higher depreciation, decommissioning and amortization expense of $54 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 $3.3 billion and $7.8 billion for the three- and nine-month periods ended September 30, 2011, respectively, compared to $3.4 billion and $7.8 billion for the respective periods in 2010. The quarterly decrease reflects a rate decrease of $186 million and a sales volume increase of $103 million. The $186 million rate decrease primarily reflects lower generation rates for 2011 due to the refunding of prior period purchased power overcollections in 2011. The $103 million sales volume increase was primarily due to serving generation load that was previously served by CDWR contracts which expired in 2011. 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 $319 million and $873 million for the three- and nine-month periods ended September 30, 2011, respectively, and $315 million and $896 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.

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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Income before income taxes	$	666		$	612		$	1,378		$	1,235
Provision for income tax at federal statutory rate of 35%	$	233		$	214		$	482		$	433
Increase (decrease) in income tax from:
Items presented with related state income tax, net
Global settlement related1	—			(42		)	—			(95		)
Change in tax accounting method for asset removal costs2	—			—			—			(40		)
State tax – net of federal benefit	31			26			61			47
Health care legislation3	—			—			—			39
Property-related and other	(19		)	7			(47		)	(46		)
Total income tax expense	$	245		$	205		$	496		$	338
Effective tax rate	37		%	33		%	36		%	27		%

¹  During the nine months ended September 30, 2010, SCE recognized a $95 million earnings benefit relating to the California impact of the federal Global Settlement, including $53 million in the second quarter resulting from the acceptance by the California Franchise Tax

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Board of the tax positions finalized with the IRS in 2009 and $42 million in the third quarter resulting from receipt of the final interest determination for the Franchise Tax Board.

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.

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."

Repair Deductions

As discussed in the year ended 2010 MD&A, in 2009, Edison International made a voluntary election to change its tax accounting method for certain repair costs incurred on SCE's transmission, distribution and generation assets. The change in tax accounting method resulted in a $192 million cash benefit realized in the fourth quarter of 2009. In August of 2011 the IRS issued guidance on repair deductions and changes in accounting method related to transmission and distribution assets. Based on this guidance SCE will file a second change in tax accounting method in 2011 for all prior years. SCE does not expect any cash impact in 2011 due to its current net operating loss carry forward position. Regulatory treatment for the incremental deductions taken after the voluntary election to change SCE's tax accounting method for certain repair costs will be addressed in SCE's 2012 GRC. Due to the pending regulatory treatment SCE has not recognized an earnings benefit or regulatory asset related to this method change and incremental deductions taken in 2009, 2010 and 2011.

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 (including bonus depreciation) 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

SCE had two credit facilities: a $2.4 billion five-year credit facility that matures in February 2013, with four one-year options to extend by mutual consent, and a $500 million three-year credit facility that matures in March 2013.

(in millions)	Credit Facilities
Commitment	$	2,894
Outstanding borrowings supported by credit facilities	(550		)
Outstanding letters of credit	(83		)
Amount available	$	2,261

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 September 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

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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 September 30, 2011, SCE's 13-month weighted-average common equity component of total capitalization was 50.5% resulting in the capacity to pay $436 million in additional dividends.

During the first nine months of 2011, SCE made $345 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.

Regulatory Proceedings

Energy Efficiency Shareholder Risk/Reward Mechanism

As discussed in the 2010 Form 10-K under the heading "Overview of Ratemaking Mechanisms—Energy Efficiency Shareholder Risk/Reward Mechanism," the CPUC intended to review the framework of the Energy Efficiency Mechanism and to establish a mechanism applicable to performance during the 2010 - 2012 energy efficiency program cycle. In September 2011 the CPUC requested comments from SCE and other interested parties on an Energy Efficiency Mechanism applicable to the 2010-2012 program cycle. SCE recommended using the remainder of 2011 and 2012 for development of a new mechanism that would focus on reliability, affordability, and benefits to the environment that would be applicable for 2013 and beyond.

Cost of Capital

As discussed in the 2010 Form 10-K under the heading "Overview of Ratemaking Mechanisms—CPUC Base Rates," the CPUC extended through 2012 a multi-year cost of capital mechanism which set SCE's authorized rate of return on equity at 11.5%, subject to annual adjustments if certain thresholds are reached. The 2012 measurement period (October 2010 - September 2011) did not trigger an annual adjustment and therefore the 11.5% authorized rate of return on equity will remain in effect through 2012. In April 2012, SCE is scheduled to file a new cost of capital mechanism at the CPUC that, once approved, will establish SCE's authorized rate of return for 2013. If the current interest rate environment continues, SCE's 2013 authorized rate of return could decrease from 11.5%.

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 September 30, 2011.

(in millions)
Collateral posted as of September 30, 20111	$	106
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade	135
Posted and potential collateral requirements2	$	241

¹  Collateral provided to counterparties and other brokers consisted of $14 million which was offset against net derivative liabilities and $92 million, which consisted of $9 million in cash reflected in “Other current assets” on the consolidated balance sheets and $83 million in letters of credit.

²  Total posted and potential collateral requirements may increase by an additional $2 million based on SCE's forward positions as of September 30, 2011 due to adverse market price movements over the remaining lives 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 September 30, 2011, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $202 million for its workers compensation self-insurance plan.

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Historical Consolidated Cash Flows

Condensed Consolidated Statement of Cash Flows

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

	Nine months ended September 30,
(in millions)	2011			2010
Net cash provided by operating activities	$	2,272		$	2,656
Net cash provided by financing activities	672			622
Net cash used by investing activities	(3,136		)	(2,883		)
Net increase (decrease) in cash and cash equivalents	$	(192	)	$	395

Net Cash Provided by Operating Activities

Net cash provided by operating activities decreased $384 million in the first nine months of 2011 compared to the first nine months of 2010. The decrease reflects net cash outflows related to regulatory balancing account activities and higher net tax receipts in 2010 primarily resulting from the impacts of the Global Settlement. As a result of the Global Settlement, SCE received net tax allocation payments from Edison International of approximately $295 million in 2010. These decreases were partially offset by higher receipts from customers due to increases in authorized revenues. 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 nine months of 2011 was $672 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 $550 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 $345 million of dividends to Edison International.

• Purchased $86 million of its variable rate tax-exempt bonds.

Net cash provided by financing activities for the first nine months of 2010 was $622 million consisting of the following significant events:

• Issued $1 billion of first refunding mortgage bonds due in 2040 to fund SCE's capital program.

• Reissued $144 million of tax-exempt pollution control bonds due in 2035 to fund SCE's capital program.

• Repaid $250 million of senior unsecured notes.

• Paid $200 million in dividends to Edison International.

Net Cash Used by Investing Activities

Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $3.0 billion and $2.7 billion for the nine months ended September 30, 2011 and 2010, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $146 million and $133 million for the nine months ended September 30, 2011 and 2010, respectively.

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Contractual Obligations and Contingencies

Contractual Obligations

SCE has power purchase commitments and firm transmission commitments which are discussed in "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

Contingencies

SCE has contingencies related to an Order Instituting Investigation ("OII") related to a 2007 wildfire in Malibu, California, 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 September 30, 2011, SCE had 24 identified material sites for remediation and recorded an estimated minimum liability of $51 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 $641 million and $207 million at September 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, including master netting agreements. As of September 30, 2011, the amount of balance sheet exposure as described above, by the credit ratings of SCE's counterparties, was as follows:

	September 30, 2011
(in millions)	Exposure2		Collateral			Net Exposure
S&P Credit Rating1
A or higher	$	98	$	—		$	98
Not rated3	5		(1		)	4
Total	$	103	$	(1	)	$	102

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.

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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 long-term power purchase agreements. SCE's exposure is mitigated by regulatory treatment.

The credit risk exposure set forth in the table above is composed of $2 million of net accounts receivable and $101 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

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EDISON MISSION GROUP

RESULTS OF OPERATIONS

Results of Continuing Operations

This section discusses operating results for the three- and nine-month periods ended September 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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Competitive power generation operating revenues	$	596		$	691		$	1,686		$	1,838
Fuel	242			228			597			602
Operation and maintenance	221			224			832			794
Depreciation and amortization	78			62			229			182
Other	—			—			8			3
Total operating expenses	541			514			1,666			1,581
Operating income	55			177			20			257
Interest and dividend income	1			4			31			28
Equity in income from unconsolidated affiliates – net	56			62			68			101
Other income, net	1			—			7			—
Interest expense	(81		)	(65		)	(244		)	(198		)
Income (loss) from continuing operations before income taxes	32			178			(118		)	188
Income tax expense (benefit)	(1		)	64			(103		)	(22		)
Income (loss) from continuing operations	33			114			(15		)	210
Income (loss) from discontinued operations – net of tax	—			(4		)	(3		)	4
Net income (loss)	33			110			(18		)	214
Less: Net income attributable to noncontrolling interests	—			—			(1		)	—
Net income (loss) available for common shareholder	$	33		$	110		$	(17	)	$	214
Core Earnings (Losses)1	$	33		$	120		$	(14	)	$	158
Non-Core Earnings (Losses)
Global Settlement	—			(6		)	—			52
Discontinued Operations	—			(4		)	(3		)	4
Total EMG GAAP Earnings (Losses)	$	33		$	110		$	(17	)	$	214

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

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

• $81 million decrease in Midwest Generation adjusted operating income primarily due to lower capacity revenues, average realized energy prices and generation, and a gain in 2010 from the sale of bankruptcy claims against Lehman Brothers Commodity Services, Inc. and Lehman Brothers Holdings Inc. (“Lehman”).

• $22 million decrease in Homer City adjusted operating income primarily due to lower capacity revenues and higher coal costs.

• $16 million increase in interest expense primarily due to higher interest related to the new energy projects financings in 2011 of $6 million and lower capitalized interest of $11 million.

• $16 million decrease in energy trading revenues partially due to reduced revenues from power trading activities. The

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decrease is also partially due to the allocation to Homer City the benefit of an arrangement that allows EMMT to deliver power into the New York Independent System Operator (“NYISO”) from Homer City. However, such decrease resulting from that allocation is offset by the increase recognized at Homer City due to the arrangement.

• $10 million decrease in renewable energy adjusted operating income primarily due to lower capacity factors driven by wind conditions.

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

• $126 million decrease in Midwest Generation adjusted operating income primarily due to lower average realized energy prices and generation, and a gain in 2010 from the sale of bankruptcy claims against Lehman.

• $85 million decrease in Homer City adjusted operating income primarily due to lower energy revenues driven by lower generation, lower capacity revenues and higher plant maintenance costs from outages. Partially offsetting the decrease were unrealized derivative gains of $3 million in 2011 compared to losses of $13 million in 2010.

• $46 million increase in interest expense due to higher interest expense primarily related to the new energy projects financings in 2011 of $28 million and lower capitalized interest of $18 million.

• $38 million decrease in energy trading revenue partially due to reduced revenues from power trading activities. The decrease is also partially due to the allocation to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. However, such decrease resulting from that allocation is offset by the increase recognized at Homer City due to the arrangement.

• $12 million decrease in adjusted operating income from the Big 4 projects due to lower capacity prices under Midway-Sunset's new power purchase agreement and lower capacity and energy sales margin.

These decreases were partially offset by the following:

• $11 million higher income from a distribution received from the Doga project in 2011, compared to 2010.

• $6 million increase in renewable energy adjusted operating income due to the increase in wind projects in operation coupled with higher generation, partially offset by lower realized energy prices at the merchant wind projects.

Non-core item for EMG included:

• An earnings benefit of $52 million recorded in the nine months ended September 30, 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.

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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 third quarters of 2011 and 2010 and nine months ended September 30, 2011 and 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

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

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Midwest Generation plants	$	69		$	150		$	72		$	198
Homer City plant1	26			48			—			85
Renewable energy projects	(2		)	8			43			37
Energy trading1	11			27			67			105
Big 4 projects	26			33			37			49
Sunrise	29			27			28			30
Doga	—			—			26			15
Other projects2	1			—			10			24
Leveraged lease income	1			2			4			4
Other operating income (expense)	(1		)	(3		)	1			(2		)
	160			292			288			545
Corporate administrative and general	(32		)	(37		)	(101		)	(111		)
Corporate depreciation and amortization	(6		)	(5		)	(18		)	(13		)
AOI3	$	122		$	250		$	169		$	421

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  Includes March Point which was 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 September 30,				Nine months ended September 30,
(in millions)	2011		2010		2011		2010
AOI	$	122	$	250	$	169	$	421
Less:
Equity in income of unconsolidated affiliates	56		61		68		100
Dividend income from projects	—		—		27		18
Production tax credits	10		12		47		45
Other income, net	1		—		7		1
Operating Income	$	55	$	177	$	20	$	257

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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 September 30,				Nine months ended September 30,
(in millions)	2011		2010		2011		2010
Operating Revenues	$	366	$	444	$	997	$	1,104
Operating Expenses
Fuel1	157		151		390		390
Plant operations	86		93		368		358
Plant operating leases	19		19		56		56
Depreciation and amortization	29		28		87		84
Asset retirements	—		—		9		3
Administrative and general	6		3		17		15
Total operating expenses	297		294		927		906
Operating Income	69		150		70		198
Other Income	—		—		2		—
AOI	$	69	$	150	$	72	$	198
Statistics
Generation (in GWh)	7,957		8,449		20,987		22,091

¹  Included in fuel costs were $1 million and $5 million during the third quarters of 2011 and 2010, respectively, and $3 million and $10 million during the nine months ended September 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 NOx emission allowances to Midwest Generation were $0.4 million during each of the nine months ended September 30, 2011 and 2010, respectively. Transfers of SO₂ emission allowances from Midwest Generation were none and $5 million during the nine months ended September 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 $81 million for the third quarter ended September 30, 2011, compared to the corresponding period of 2010. The third quarter decrease in AOI was primarily attributable to lower energy and capacity revenues and a gain in 2010 from the sale of bankruptcy claims against Lehman. During the third quarter of 2010, EME sold its bankruptcy claims against Lehman and recorded a gain of $24 million. The decline in energy revenues was due to lower generation and lower average realized energy prices and the decline in capacity revenues was due to lower capacity prices from the RPM auction.

AOI from the Midwest Generation plants decreased $126 million for the nine months ended September 30, 2011, compared to the corresponding period of 2010. The 2011 decrease in AOI was primarily attributable to lower energy revenues and a gain in 2010 from the sale of the bankruptcy claims discussed above. 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 losses from hedge activities of $3 million and $16 million for the third quarters of 2011 and 2010, respectively, and $1 million and $12 million for the nine months ended September 30, 2011 and 2010, respectively. Unrealized losses in 2011 and 2010 were primarily attributable to economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of operations.

Included in fuel costs were unrealized gains (losses) of $(4) million and $2 million during the third quarters of 2011 and 2010, respectively, and $(6) million and $(5) million for the nine months ended September 30, 2011 and 2010, respectively. Unrealized gains (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.

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Homer City

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

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2011		2010		2011		2010
Operating Revenues1	$	159	$	173	$	410	$	477
Operating Expenses
Fuel2	81		74		196		201
Plant operations	21		20		118		95
Plant operating leases	25		25		76		77
Depreciation and amortization	6		5		16		14
Asset retirements	—		—		—		1
Administrative and general	—		1		4		4
Total operating expenses	133		125		410		392
Operating Income	26		48		—		85
AOI	$	26	$	48	$	—	$	85
Statistics
Generation (in GWh)	2,800		2,984		6,969		8,227

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 $2 million and $1 million during the third quarters of 2011 and 2010, respectively, and $3 million and $6 million during the nine months ended September 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 nine months ended September 30, 2011 and 2010, respectively. Transfers of NOx emission allowances from Homer City were $0.4 million during each of the nine months ended September 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 $22 million for the third quarter ended September 30, 2011, compared to the corresponding period of 2010. The third quarter decrease in AOI was primarily attributable to lower capacity revenues and higher coal costs.

AOI from the Homer City plant decreased $85 million for nine months ended September 30, 2011, compared to the corresponding period of 2010. The 2011 decrease in AOI was attributable to lower energy revenues driven by lower generation, lower capacity revenues, 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 primarily due to lower generation, mostly offset by higher coal costs.

Included in operating revenues were unrealized gains (losses) from hedge activities of $(2) million and $1 million for the third quarters of 2011 and 2010, respectively, and $3 million and $(13) million for the nine months ended September 30, 2011 and 2010, respectively. Unrealized gains (losses) 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 gains (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).

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

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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 September 30,					Nine months ended September 30,
(in millions)	2011			2010		2011		2010
Operating Revenues	$	44		$	29	$	155	$	93
Production Tax Credits	10			12		47		45
	54			41		202		138
Operating Expenses
Plant operations	20			11		56		35
Depreciation and amortization	35			21		103		64
Administrative and general	1			1		3		2
Total operating expenses	56			33		162		101
Equity in loss from unconsolidated affiliates	(1		)	—		—		—
Other Income	1			—		3		—
AOI1	$	(2	)	$	8	$	43	$	37
Statistics
Generation (in GWh)2	953			764		3,893		2,599

¹  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 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 EME. Generation, excluding unconsolidated projects, was 819 GWh and 643 GWh in the third quarters of 2011 and 2010, respectively, and 3,356 GWh and 2,156 GWh in the nine months ended September 30, 2011 and 2010, respectively.

AOI from renewable energy projects decreased $10 million in the third quarter and increased $6 million in the nine months ended September 30, 2011, compared to the corresponding periods of 2010. The decrease in the third quarter was primarily due to lower capacity factors driven by wind conditions. The year-to-date increase was primarily due to projects that achieved commercial operation in late 2010 and 2011 and increased generation at other projects due to higher availability and favorable wind conditions during the first half of 2011, partially offset by lower realized prices from the merchant wind projects.

Energy Trading

AOI from energy trading activities decreased $16 million and $38 million for the third quarter and nine months ended September 30, 2011, respectively, compared to the corresponding periods of 2010. The third quarter and year-to-date decreases were partially due to reduced revenues from power trading activities and partially due to the allocation to Homer City of the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City.

Adjusted Operating Income from Other Projects

Big 4 Projects.    AOI from the Big 4 projects decreased in 2011, compared to the corresponding periods in 2010, primarily due to lower capacity prices under Midway-Sunset's new power purchase agreement and lower capacity and energy sales margin.

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Doga.    EMG received distributions of $26 million from the Doga project in the second quarter of 2011 and $15 million in the first quarter of 2010. The increase in distribution is primarily due to elimination of restricted cash as a result of the repayment of the remaining project debt. 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.

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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Interest expense, net of capitalized interest
EME debt	$	(66	)	$	(56	)	$	(191	)	$	(174	)
Non-recourse debt	(15		)	(9		)	(53		)	(24		)
	$	(81	)	$	(65	)	$	(244	)	$	(198	)

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 $4 million and $20 million for the third quarter and nine months ended September 30, 2011, respectively, compared to $15 million and $38 million for the third quarter and nine months ended September 30, 2010, respectively.

Income Taxes

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

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Income (loss) from continuing operations before income taxes	$	32		$	178		$	(118	)	$	188
Provision (benefit) for income taxes at federal statutory rate of 35%	$	11		$	62		$	(41	)	$	66
Increase (decrease) in income tax from:
State tax – net of federal provision (benefit)	1			8			(8		)	9
Tax credits, net	(12		)	(16		)	(49		)	(50		)
Global Settlement related	—			6			—			(52		)
Other	(1		)	4			(5		)	5
Total income tax expense (benefit)	$	(1	)	$	64		$	(103	)	$	(22	)
Effective tax rate	(3		)%	36		%	87		%	(12		)%

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."

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LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

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

(in millions)	Cash and Cash Equivalents		Available Under Credit Facilities		Total Available Liquidity
EME as a holding company	$	539	$	499	$	1,038
EME subsidiaries without contractual dividend restrictions	195		—		195
EME corporate cash and cash equivalents	734		499		1,233
EME subsidiaries with contractual dividend restrictions
Midwest Generation1	333		497		830
Homer City	108		—		108
Other EME subsidiaries	60		—		60
Other EMG subsidiaries	41				41
Total	$	1,276	$	996	$	2,272

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."

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

(in millions)	EME			Midwest Generation
Commitments	$	564		$	500
Outstanding borrowings	—			—
Outstanding letters of credit	(65		)	(3		)
Amount available	$	499		$	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 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. At September 30, 2011, the equity rent reserve balance was restored back to $20 million, and Homer City had delivered energy sufficient to eliminate the accelerated payments by EMMT. Homer City must continue to make equity rent payments in order to be entitled to make future distributions. 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

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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. 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."

Capital Investment Plan

Forecasted capital expenditures through 2013 by EMG's subsidiaries for existing projects, corporate activities and turbine commitments are as follows:

(in millions)	October through December 2011		2012			2013
Midwest Generation Plants
Environmental1	$	26	$	172		$	316
Plant capital	5		22			29
Homer City Plant
Environmental1	13		—			—
Plant capital	1		26			16
Walnut Creek Project	78		223		72	72
Renewable Energy Projects
Capital and construction	92		108			—
Other capital	5		14			14
Total	$	220	$	565		$	447

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 $13 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, assuming all units are retrofitted for an estimated aggregate cost of $1.2 billion. EMG believes that Midwest Generation's current environmental remediation plan developed to comply with the CPS, along with the allowances allocated to it under CSAPR, will be sufficient to comply with the requirements of CSAPR and the US EPA's proposed regulation on HAP emissions. In order to achieve compliance, Midwest Generation has begun work to install SO₂ controls at certain of its plants. 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.

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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.

Renewable Energy Projects

In the third quarter of 2011, EMG acquired the 80 MW Broken Bow I and the 40 MW Crofton Bluffs wind projects. Commercial operations of the Broken Bow I and the Crofton Bluffs projects are expected in the fourth quarter of 2012. The Taloga wind project achieved commercial operation on July 13, 2011.

At September 30, 2011, EMG had a development pipeline of potential wind projects with projected installed capacity of approximately 3,800 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 September 30, 2011, EMG had capitalized costs and turbine deposits totaling $26 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.

Funding of Capital Expenditures

In July, EME secured $495 million in construction and term financing for the Walnut Creek project. 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." EMG 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. EMG received a total of $310 million of U.S. Treasury grants in the third quarter of 2011 and used $57 million to repay the Laredo Ridge bridge loan. Additional U.S. Treasury grants of approximately $135 million are anticipated for the remainder of 2011 and in 2012 based on estimated eligible construction costs for renewable energy projects.

Historical Segment Cash Flows

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

Condensed Statement of Cash Flows

	Nine months ended September 30,
(in millions)	2011			2010
Operating cash flow from continuing operations	$	567		$	289
Operating cash flow from discontinued operations	(3		)	4
Net cash provided by operating activities	564			293
Net cash provided by financing activities	112			83
Net cash used by investing activities	(498		)	(443		)
Net increase (decrease) in cash and cash equivalents	$	178		$	(67	)

Net Cash Provided by Operating Activities

The increase in the first nine months of 2011 as compared to the first nine months of 2010 in cash provided by operating activities from continuing operations was primarily attributable to a $253 million deposit paid by Edison Capital to the IRS in 2010 related to the Global Settlement, tax-allocation payments received by EME in 2011 of $182 million compared to $100 million in 2010, and $310 million of U.S. Treasury grants received in 2011 compared to $92 million in 2010. These increases were partially offset by lower pre-tax income.

Net Cash Provided by Financing Activities

The increase in the first nine months of 2011 as compared to the first nine months of 2010 in cash provided by financing activities from continuing operations was primarily attributable to borrowings at the Walnut Creek gas project in 2011, partially offset by higher borrowings at wind projects in 2010 than in 2011.

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Net Cash Provided by Investing Activities

Cash used in investing activities for the first nine months of 2011 and 2010 primarily consisted of capital expenditures for construction of energy projects and other plant improvements.

Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT as of September 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.

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. As of September 30, 2011, there were no open positions under hedge contracts that would require EMMT to provide adequate assurance in the form of additional credit support.

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 September 30, 2011 if wholesale energy prices change or if EMMT enters into additional transactions. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding at September 30, 2011 could increase by approximately $82 million over the remaining life of the contracts using a 95% confidence level.

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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
	September 30, 2011	December 31, 2010
Ratio	2.49	2.07
Covenant threshold (not less than)	1.20	1.20

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

	September 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 September 30, 2011 or for the 12 months ended September 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	0.13 to 1
Homer City (Homer City plant)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	1.64 to 1

As indicated above, the actual senior rent service coverage ratio was below the covenant threshold for the 12 months ended September 30, 2011, which currently precludes Homer City from making distributions, including repayment of certain intercompany loans. For additional information, see “Management's Overview of EMG—Homer City Capital Needs and Liquidity” and "Edison Mission Group—Liquidity and Capital Resources—Available Liquidity—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 September 30, 2011, the maximum permissible sale or disposition of EME assets was $898 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 and Coal Transportation Agreements

For a discussion of fuel supply contracts and coal transportation agreements, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments—Fuel Supply Contracts and Coal Transportation Agreements."

Turbine Commitments

For a discussion of turbine commitments, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments—Turbine Commitments."

Capital Commitments

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

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.

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Derivative Instruments

Unrealized Gains and Losses

EMG classifies unrealized gains and losses from derivative instruments (other than the effective portion of derivatives that qualify for hedge accounting) as part of operating revenues or fuel costs. The following table summarizes unrealized gains (losses) from non-trading activities:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Midwest Generation plants
Non-qualifying hedges	$	(8	)	$	(12	)	$	(7	)	$	(18	)
Ineffective portion of cash flow hedges	1			(2		)	—			1
Homer City plant
Non-qualifying hedges	(6		)	—			(3		)	—
Ineffective portion of cash flow hedges	4			1			6			(13		)
Total unrealized losses	$	(9	)	$	(13	)	$	(4	)	$	(30	)

At September 30, 2011, cumulative unrealized losses of $2 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods (unrealized losses of $5 million for the remainder of 2011 and unrealized gains of $3 million for 2012).

Fair Value Disclosures

In determining the fair value of EMG's derivative positions, EMG uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EMG's derivative instruments, see "Edison International Notes to Consolidated Financial Statements—Note 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 nine months of 2011 and 2010:

	24-Hour Average Historical Market Prices1
	2011		2010
Midwest Generation plants
Northern Illinois Hub	$	35.39	$	35.02
Homer City plant
PJM West Hub	46.38		46.65
Homer City Busbar	42.14		39.80

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.

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The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at September 30, 2011:

	24-Hour Forward Energy Prices1
	Northern Illinois Hub		PJM West Hub
2011
October	$	26.05	$	38.10
November	27.27		38.97
December	31.10		46.02
2012 calendar "strip"2	33.67		45.46
2013 calendar "strip"2	36.48		48.46

¹  Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub and PJM West Hub delivery points.

²  Market price for energy purchases for the entire calendar year.

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

EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services contracts and forward contracts accounted for on the accrual basis) at September 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	3,959	$	38.61	8,206	$	37.60	1,020	$	39.11
Homer City plant3,4
PJM West Hub	1,145	51.37		1,319	51.79		204	51.85
Total	5,104			9,525			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 165 MW of capacity for periods ranging from October 1, 2011 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

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Capacity Price Risk

The following table summarizes the status of capacity sales for Midwest Generation and Homer City at September 30, 2011:

	Installed Capacity MW	Unsold Capacity1 MW		Capacity Sold2 MW	RPM Capacity Sold in Base Residual Auction			Other Capacity Sales, Net of Purchases3				Aggregate Average Price per MW-day
					MW	Price per MW-day		MW		Average Price per MW-day
October 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 165 MW of capacity for periods ranging from October 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.

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 nine months ended September 30, 2011 and 2010, prices at the Homer City busbar were lower than the PJM West Hub by an average of 9% and 15%, respectively, due to transmission congestion in PJM. During the nine months ended September 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 12%, 1% and 1%, respectively, compared to 10%, 1% and 1%, respectively, during the nine months ended September 30, 2011, due to transmission congestion in PJM.

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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 September 30, 2011 for the remainder of 2011 and the following three years:

	Amount of Coal Under Contract in Millions of Equivalent Tons1
	October through December 2011	2012	2013	2014
Midwest Generation plants	5.0	13.7	9.8	9.8
Homer City plant	1.8	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.

EMG is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal are related to the price of coal purchased for the Homer City plant. 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 $77.25 per ton at September 30, 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 $15 per ton during the first nine months of 2011. The market price of PRB coal increased to a price of $15 per ton at September 30, 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. EMG expects to finalize a new long-term contract for the transport of coal during the fourth quarter of 2011.

Emission Allowances Price Risk

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. EMG 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 Management Overview—Management Overview of EMG—Cross-State Air Pollution Rule” and "Edison International Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments—Environmental Developments—Cross-State Air Pollution Rule."

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Credit Risk

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

	September 30, 2011
(in millions)	Exposure2		Collateral			Net Exposure
Credit Rating1
A or higher	$	105	$	(7	)	$	98
A-	2		—			2
BBB+	15		—			15
BBB-	7		—			7
Below investment grade	24		(23		)	1
Total	$	153	$	(30	)	$	123

¹  EMG assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.

²  Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheet, except for any related accounts receivable.

The credit risk exposure set forth in the above table is composed of $87 million of net accounts receivable and payables and $67 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 $44 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 70% of EMG's consolidated operating revenues for the nine months ended September 30, 2011. At September 30, 2011, EMG's account receivable due from PJM was $58 million.

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

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 $(13) million and $6 million for the three months ended September 30, 2011 and 2010, respectively, and $(19) million and $18 million for the nine months ended September 30, 2011 and 2010, respectively. Results for the three- and nine-month periods ended September 30, 2010 included 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 of $1 million and $28 million, respectively.

Results for the three- and nine-month periods ended September 30, 2011 included consolidated tax expense (benefit) of $4 million and $(7) million, respectively, compared to $(14) million and $(10) million for the respective periods in 2010, from differences in the allocation of state income taxes to subsidiaries under tax allocation agreements.

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 September 30, 2011, Edison International (parent) had $21 million of cash and equivalents on hand. The following table summarizes the status of the Edison International (parent) credit facility at September 30, 2011:

(in millions)	Edison International (parent)
Commitment	$	1,426
Outstanding borrowings	(10		)
Outstanding letters of credit	—
Amount available	$	1,416

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 September 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.

	Nine months ended September 30,
(in millions)	2011			2010
Net cash used by operating activities	$	(13	)	$	(200	)
Net cash provided by financing activities	21			200
Net cash provided by investing activities	1			7
Net increase in cash and cash equivalents	$	9		$	7

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). During the nine months ended September 30, 2010, Edison International received $134 million in taxes related to the Global Settlement and made tax allocation payments to SCE of $295 million.

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Net Cash Provided (Used) by Financing Activities

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

• Paid $313 million of dividends to Edison International common shareholders.

• Received $345 million of dividend payments from SCE.

• Repaid $9 million under Edison International's line of credit.

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

• Issued $400 million of senior notes due in 2017. The proceeds from these bonds were used to repay short-term borrowings under the revolving credit facility and the remainder for corporate liquidity purposes.

• Paid $308 million of dividends to Edison International common shareholders.

• Received $200 million of dividend payments from SCE.

• Repaid $85 million under Edison International's line of credit.

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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.

Internal Control Over Financial Reporting

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

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

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resolve any remaining claims among themselves pertaining to the NOV.

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 in the US EPA's New Source Review litigation 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. A motion filed by the plaintiffs requesting that the dismissals be certified as “partial final judgments” capable of appeal, and requesting that the remaining claims be stayed pending such an appeal, is pending.

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 sought to have their suits certified as a class action and requested injunctive relief, as well as compensatory and punitive damages. In October 2011, the complaints were dismissed for lack of federal jurisdiction.

Homer City New Source Review and Other Litigation

On October 12, 2011, all of the claims in the US EPA's New Source Review litigation were dismissed with prejudice. On October 13, 2011, the claims in the purported class action that were based on the federal CAA were dismissed with prejudice, while state law statutory and common law claims were dismissed without prejudice to re-file in state court should the plaintiffs choose to do so.

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
July 1, 2011 to July 31, 2011	160,830	$	38.44	—	—
August 1, 2011 to August 31, 2011	1,017,331	$	36.48	—	—
September 1, 2011 to September 30, 2011	485,092	$	36.66	—	—
Total	1,663,253	$	36.72	—	—

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.

78

ITEM 5. OTHER INFORMATION

On October 27, 2011, the Edison International Board of Directors amended the emergency provisions of the Edison International Bylaws to reduce the period of notice required to call a meeting in an emergency and to eliminate other special emergency provisions. In addition to the amendments to the emergency provisions, the Edison International Bylaws were amended to: (1) clarify that the place of shareholder and Board meetings may be designated in the meeting notice, and (2) shorten the normal Board meeting notice requirement from 48 to 24 hours.

ITEM 6. EXHIBITS

3.1	Bylaws of Edison International, as amended October 27, 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 September 30, 2011, filed on November 2, 2011, formatted in XBRL: (i) the Consolidated Statements of Income; (ii) the Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; and (v) the Notes to the Consolidated Financial Statements

79

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: November 2, 2011

80

EX-3.1

Exhibit 3.1

BYLAWS

OF

EDISON INTERNATIONAL

(AS AMENDED OCTOBER 27, 2011)

INDEX
	Page
ARTICLE I - PRINCIPAL OFFICE
Section 1. Principal Office	1
ARTICLE II - SHAREHOLDERS
Section 1. Meeting Locations	1
Section 2. Annual Meetings	1
Section 3. Special Meetings	2
Section 4. Notice of Annual or Special Meeting	2
Section 5. Quorum	3
Section 6. Adjourned Meeting and Notice Thereof	4
Section 7. Voting	4
Section 8. Record Date	6
Section 9. Consent of Absentees	7
Section 10. Action Without Meeting	7
Section 11. Proxies	8
Section 12. Inspectors of Election	8
ARTICLE III - DIRECTORS
Section 1. Powers	9
Section 2. Number of Directors	9
Section 3. Election and Term of Office	10
Section 4. Vacancies	10
Section 5. Place of Meeting	11
Section 6. Organization Meeting	11
Section 7. Special Meetings and Other Regular Meetings	11
Section 8. Quorum	12
Section 9. Participation in Meetings by Conference Telephone	12
Section 10. Waiver of Notice	12
Section 11. Adjournment	12
Section 12. Fees and Compensation	12
Section 13. Action Without Meeting	13

i

Section 14. Rights of Inspection	13
Section 15. Committees	13
ARTICLE IV - OFFICERS
Section 1. Officers	14
Section 2. Election	14
Section 3. Eligibility of Chairman	14
Section 4. Removal and Resignation	14
Section 5. Appointment of Other Officers	15
Section 6. Vacancies	15
Section 7. Salaries	15
Section 8. Furnish Security for Faithfulness	15
Section 9. Chairman's Duties; Succession to
Such Duties in Chairman's Absence or Disability	15
Section 11. Chief Financial Officer	16
Section 12. Vice Presidents' Duties	16
Section 13. General Counsel's Duties	16
Section 14. Associate General Counsel's and Assistant General
Counsel's Duties	16
Section 15. Controller's Duties	17
Section 16. Assistant Controllers' Duties	17
Section 17. Treasurer's Duties	17
Section 18. Assistant Treasurers' Duties	17
Section 19. Secretary's Duties	17
Section 20. Assistant Secretaries' Duties	18
Section 21. Secretary Pro Tempore	18
Section 22. Election of Acting Treasurer or Acting Secretary	18
Section 23. Performance of Duties	19
ARTICLE V - OTHER PROVISIONS
Section 1. Inspection of Corporate Records	19
Section 2. Inspection of Bylaws	20
Section 3. Contracts and Other Instruments, Loans, Notes
and Deposits of Funds	20

ii

Section 4. Certificates of Stock and Uncertificated Stock	21
Section 5. Transfer Agent, Transfer Clerk and Registrar	22
Section 6. Representation of Shares of Other Corporations	22
Section 7. Stock Purchase Plans	22
Section 8. Fiscal Year and Subdivisions	22
Section 9. Construction and Definitions	23
ARTICLE VI - INDEMNIFICATION
Section 1. Indemnification of Directors and Officers	23
Section 2. Indemnification of Employees and Agents	24
Section 3. Right of Directors and Officers to Bring Suit	25
Section 4. Successful Defense	25
Section 5. Non-Exclusivity of Rights	25
Section 6. Insurance	25
Section 7. Expenses as a Witness	25
Section 8. Indemnity Agreements	26
Section 9. Separability	26
Section 10. Effect of Repeal or Modification	26
ARTICLE VII - EMERGENCY PROVISIONS
Section 1. General	26
Section 2. Notice of Meetings	27
Section 3. Quorum	27
ARTICLE VIII - AMENDMENTS
Section 1. Amendments	27

iii

BYLAWS

OF

EDISON INTERNATIONAL

(As Amended October 27, 2011)

ARTICLE I - PRINCIPAL OFFICE

Section 1.Principal Office.

The principal office of the Corporation is hereby fixed and located at 2244 Walnut Grove Avenue, in the City of Rosemead, County of Los Angeles, State of California. The Board of Directors is hereby granted full power and authority to change said principal office from one location to another.

ARTICLE II - SHAREHOLDERS

Section 1.Meeting Locations.

All meetings of shareholders shall be held at the principal office of the corporation or at such other place or places within or without the State of California as may be designated by the Board of Directors (the "Board") or specified in the notice of the meeting. In the event such places shall prove inadequate in capacity for any meeting of shareholders, an adjournment may be taken to and the meeting held at such other place of adequate capacity as may be designated by the officer of the corporation presiding at such meeting.

Section 2.Annual Meetings.

Annual meetings of shareholders shall be held on the fourth Thursday of the month of April of each year at such time as the Chairman of the Board shall designate on said day to elect directors to hold office for the year next ensuing and until their successors shall be elected, and to consider and act upon such other matters as may lawfully be presented to such meeting; provided, however, that should said day fall upon a legal holiday, then any such annual meeting of shareholders shall be held at such designated time and place on the next day thereafter ensuing which is not a legal holiday.

1

ARTICLE II

Section 3.Special Meetings.

Special meetings of the shareholders may be called at any time by the Board, the Chairman of the Board, the President, or upon written request of any three members of

the Board, or by the holders of shares entitled to cast not less than ten percent of the votes at such meeting. Upon request in writing to the Chairman of the Board, the President, any Vice President or the Secretary by any person (other than the Board) entitled to call a special meeting of shareholders, the officer forthwith shall cause notice to be given to the shareholders entitled to vote that a meeting will be held at a time requested by the person or persons calling the meeting, not less than thirty-five nor more than sixty days after the receipt of the request. If the notice is not given within twenty days after receipt of the request, the persons entitled to call the meeting may give the notice.

Section 4.Notice of Annual or Special Meeting.

Written notice of each annual or special meeting of shareholders shall be given not less than ten (or if sent by third-class mail, thirty) nor more than sixty days before the date of the meeting to each shareholder entitled to vote thereat. Such notice shall state the place, date, and hour of the meeting and (i) in the case of a special meeting, the general nature of the business to be transacted, and no other business may be transacted, or (ii) in the case of an annual meeting, those matters which the Board, at the time of the mailing of the notice, intends to present for action by the shareholders, but, subject to the provisions of applicable law and these Bylaws, any proper matter may be presented at an annual meeting for such action. The notice of any special or annual meeting at which directors are to be elected shall include the names of nominees intended at the time of the notice to be presented by the Board for election. For any matter to be presented by a shareholder at an annual meeting, including the nomination of any person (other than a person nominated by or at the direction of the Board) for election to the Board, written notice must be received by the Secretary of the corporation from the shareholder not more than one hundred eighty days nor less than one hundred twenty days prior to the date on which the proxy materials for the prior year's annual meeting were first released to shareholders by the corporation; provided however, that in the event the annual meeting to which the shareholder's written notice relates is to be held on a date which is more than thirty days earlier or later than the date of the annual meeting specified in these Bylaws, the notice from a shareholder must be received by the Secretary not earlier than two hundred twenty days prior to the date of the annual meeting to which the shareholder's notice relates nor later than one hundred sixty days prior to the date of such annual meeting, unless less than one hundred seventy days' prior public disclosure of the date of the meeting is made by the earliest possible quarterly report on Form 10-Q, or, if impracticable, any means reasonably calculated to inform shareholders including without limitation a report on Form 8-K, a press release or publication once in a newspaper of general circulation in the county in which the principal office is located, in which event

2

ARTICLE II

notice by the shareholder to be timely must be received not later than the close of business on the tenth day following the date of such public disclosure. The shareholder's notice to the Secretary shall set forth (a) a brief description of each matter to be presented at the annual meeting by the shareholder; (b) the name and address, as they appear on the corporation's books, of the shareholder; (c) the class and number of shares of the corporation which are beneficially owned by the shareholder; and (d) any material interest of the shareholder in the matters to be presented. Any shareholder who intends to nominate a candidate for election as a director shall also set forth in such a notice (i) the name, age, business address and residence address of each nominee that he or she intends to nominate at the meeting, (ii) the principal occupation or employment of each nominee, (iii) the class and number of shares of capital stock of the corporation beneficially owned by each nominee, and (iv) any other information concerning the nominee that would be required under the rules of the Securities and Exchange Commission in a proxy statement soliciting proxies for the election of the nominee. The notice shall also include a consent, signed by the shareholder's nominees, to serve as a director of the corporation if elected. Notwithstanding anything in these Bylaws to the contrary, and subject to the provisions of any applicable law, no business shall be conducted at a special or annual meeting except in accordance with the procedures set forth in this Section 4.

Notice of a shareholders' meeting shall be given either personally or by first-class mail (or, if the outstanding shares of the corporation are held of record by 500 or more persons on the record date for the meeting, by third-class mail) or by other means of written communication, addressed to the shareholder at the address of such shareholder appearing on the books of the corporation or given by the shareholder to the corporation for the purpose of notice; or, if no such address appears or is given, at the place where the principal office of the corporation is located or by publication at least once in a newspaper of general circulation in the county in which the principal office is located. Notice by mail shall be deemed to have been given at the time a written notice is deposited in the United States mails, postage prepaid. Any other written notice shall be deemed to have been given at the time it is personally delivered to the recipient or is delivered to a common carrier for transmission, or actually transmitted by the person giving the notice by electronic means, to the recipient.

Section 5.Quorum.

A majority of the shares entitled to vote, represented in person or by proxy, shall constitute a quorum at any meeting of shareholders. The affirmative vote of a majority of the shares represented and voting at a duly held meeting at which a quorum is present (which shares voting affirmatively also constitute at least a majority of the required quorum) shall be the act of the shareholders, unless the vote of a greater number or voting by classes is required by law or the Articles; provided, however, that the shareholders present at a duly called or held meeting at which a quorum is present may continue to do business until adjournment, notwithstanding the withdrawal of enough shareholders to

3

ARTICLE II

have less than a quorum, if any action taken (other than adjournment) is approved by at least a majority of the shares required to constitute a quorum.

Section 6.Adjourned Meeting and Notice Thereof.

Any shareholders' meeting, whether or not a quorum is present, may be adjourned from time to time by the vote of a majority of the shares, the holders of which are either present in person or represented by proxy thereat, but in the absence of a quorum (except as provided in Section 5 of this Article) no other business may be transacted at such meeting.

It shall not be necessary to give any notice of the time and place of the adjourned meeting or of the business to be transacted thereat, other than by announcement at the meeting at which such adjournment is taken. At the adjourned meeting, the corporation may transact any business which might have been transacted at the original meeting. However, when any shareholders' meeting is adjourned for more than forty-five days or, if after adjournment a new record date is fixed for the adjourned meeting, notice of the adjourned meeting shall be given as in the case of an original meeting.

Section 7.Voting.

The shareholders entitled to notice of any meeting or to vote at any such meeting shall be only persons in whose name shares stand on the stock records of the corporation on the record date determined in accordance with Section 8 of this Article.

Voting shall in all cases be subject to the provisions of Chapter 7 of the California General Corporation Law, and to the following provisions:

(a)    Subject to clause (g), shares held by an administrator, executor, guardian, conservator or custodian may be voted by such holder either in person or by proxy, without a transfer of such shares into the holder's name; and shares standing in the name of a trustee may be voted by the trustee, either in person or by proxy, but no trustee shall be entitled to vote shares held by such trustee without a transfer of such shares into the trustee's name.

(b)    Shares standing in the name of a receiver may be voted by such receiver; and shares held by or under the control of a receiver may be voted by such receiver without the transfer thereof into the receiver's name if authority to do so is contained in the order of the court by which such receiver was appointed.

(c)    Subject to the provisions of Section 705 of the California General Corporation Law and except where otherwise agreed in writing between the parties, a shareholder whose shares are pledged shall be entitled to vote such shares until the shares

4

ARTICLE II

have been transferred into the name of the pledgee, and thereafter the pledgee shall be entitled to vote the shares so transferred.

(d)    Shares standing in the name of a minor may be voted and the corporation may treat all rights incident thereto as exercisable by the minor, in person or by proxy, whether or not the corporation has notice, actual or constructive, of the non-age unless a guardian of the minor's property has been appointed and written notice of such appointment given to the corporation.

(e)    Shares standing in the name of another corporation, domestic or foreign, may be voted by such officer, agent or proxyholder as the bylaws of such other corporation may prescribe or, in the absence of such provision, as the Board of Directors of such other corporation may determine or, in the absence of such determination, by the chairman of the board, president or any vice president of such other corporation, or by any other person authorized to do so by the chairman of the board, president or any vice president of such other corporation. Shares which are purported to be voted or any proxy purported to be executed in the name of a corporation (whether or not any title of the person signing is indicated) shall be presumed to be voted or the proxy executed in accordance with the provisions of this subdivision, unless the contrary is shown.

(f)    Shares of the corporation owned by any of its subsidiaries shall not be entitled to vote on any matter.

(g)    Shares of the corporation held by the corporation in a fiduciary capacity, and shares of the corporation held in a fiduciary capacity by any of its subsidiaries, shall not be entitled to vote on any matter, except to the extent that the settlor or beneficial owner possesses and exercises a right to vote or to give the corporation binding instructions as to how to vote such shares.

(h)    If shares stand of record in the names of two or more persons, whether fiduciaries, members of a partnership, joint tenants, tenants in common, husband and wife as community property, tenants by the entirety, voting trustees, persons entitled to vote under a shareholder voting agreement or otherwise, or if two or more persons (including proxyholders) have the same fiduciary relationship respecting the same shares, unless the secretary of the corporation is given written notice to the contrary and is furnished with a copy of the instrument or order appointing them or creating the relationship wherein it is so provided, their acts with respect to voting shall have the following effect:

(i) If only one votes, such act binds all;

(ii) If more than one vote, the act of the majority so voting binds all;

5

ARTICLE II

(iii) If more than one vote, but the vote is evenly split on any particular matter, each faction may vote the securities in question proportionately.

If the instrument so filed or the registration of the shares shows that any such tenancy is held in unequal interests, a majority or even split for the purpose of this section shall be a majority or even split in interest.

No shareholder of any class of stock of this corporation shall be entitled to cumulate votes at any election of directors of this corporation.

Elections for directors need not be by ballot; provided, however, that all elections for directors must be by ballot upon demand made by a shareholder at the meeting and before the voting begins.

In any uncontested election of directors, approval of the shareholders (as defined in Section 153 of the California General Corporation Law) shall be required to elect a director. If an incumbent director fails to be elected by approval of the shareholders in an uncontested election, then, unless the incumbent director has earlier resigned, the term of the incumbent director shall end on the date that is the earlier of 90 days after the date on which the voting results are determined pursuant to Section 707 of the California General Corporation Law or the date on which the Board selects a person to fill the office held by that director in accordance with the procedures set forth in Article III, Section 4 of these Bylaws and Section 305 of the California General Corporation Law.

In any election of directors that is not an uncontested election, the candidates receiving the highest number of affirmative votes of the shares entitled to be voted for them up to the number of directors to be elected by such shares shall be elected, and votes against a director and votes withheld shall have no legal effect.

For purposes of these Bylaws, an “uncontested election” means an election of directors of this corporation in which the number of candidates for election does not exceed the number of directors to be elected by the shareholders at that election, determined at the expiration of the time fixed under Article II, Section 4 of these Bylaws requiring advance notification of director candidates, or for special meetings of shareholders, at the date notice of the meeting is given or at a time fixed by the Board that is not more than 14 days before notice of the meeting is given.

Section 8.Record Date.

The Board may fix, in advance, a record date for the determination of the shareholders entitled to notice of any meeting or to vote or entitled to receive payment of any dividend or other distribution, or any allotment of rights, or to exercise rights in

6

ARTICLE II

respect of any other lawful action. The record date so fixed shall be not more than sixty days nor less than ten days prior to the date of the meeting nor more than sixty days prior to any other action. When a record date is so fixed, only shareholders of record at the close of business on that date are entitled to notice of and to vote at the meeting or to receive the dividend, distribution, or allotment of rights, or to exercise the rights, as the case may be, notwithstanding any transfer of shares on the books of the corporation after the record date, except as otherwise provided by law or these Bylaws. A determination of shareholders of record entitled to notice of or to vote at a meeting of shareholders shall apply to any adjournment of the meeting unless the Board fixes a new record date for the adjourned meeting. The Board shall fix a new record date if the meeting is adjourned for more than forty-five days.

If no record date is fixed by the Board, the record date for determining shareholders entitled to notice of or to vote at a meeting of shareholders shall be at the close of business on the business day next preceding the day on which notice is given or, if notice is waived, at the close of business on the business day next preceding the day on which the meeting is held. The record date for determining shareholders for any purpose other than as set forth in this Section 8 or Section 10 of this Article shall be at the close of business on the day on which the Board adopts the resolution relating thereto, or the sixtieth day prior to the date of such other action, whichever is later.

Section 9.Consent of Absentees.

The transactions of any meeting of shareholders, however called and noticed, and wherever held, are as valid as though had at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy, and if, either before or after the meeting, each of the persons entitled to vote, not present in person or by proxy, signs a written waiver of notice or a consent to the holding of the meeting or an approval of the minutes thereof. All such waivers, consents or approvals shall be filed with the corporate records or made a part of the minutes of the meeting. Neither the business to be transacted at nor the purpose of any regular or special meeting of shareholders need be specified in any written waiver of notice, consent to the holding of the meeting or approval of the minutes thereof, except as provided in Section 601 (f) of the California General Corporation Law.

Section 10.Action Without Meeting.

Subject to Section 603 of the California General Corporation Law, any action which, under any provision of the California General Corporation Law, may be taken at any annual or special meeting of shareholders may be taken without a meeting and without prior notice if a consent in writing, setting forth the action so taken, shall be signed by the holders of outstanding shares having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all

7

ARTICLE II

shares entitled to vote thereon were present and voted. Unless a record date for voting purposes be fixed as provided in Section 8 of this Article, the record date for determining shareholders entitled to give consent pursuant to this Section 10, when no prior action by the Board has been taken, shall be the day on which the first written consent is given.

Section 11.Proxies.

Every person entitled to vote shares has the right to do so either in person or by one or more persons, not to exceed three, designated by a proxy authorized by such shareholder or the shareholder's attorney in fact and filed with the corporation, in accordance with Section 178 of the California General Corporation Law. Subject to the following sentence, any proxy duly authorized continues in full force and effect until revoked by the person authorizing it prior to the vote pursuant thereto by a writing delivered to the corporation stating that the proxy is revoked or by a subsequent proxy authorized by the person authorizing the prior proxy and presented to the meeting, or by attendance at the meeting and voting in person by the person authorizing the proxy; provided, however, that a proxy is not revoked by the death or incapacity of the maker unless, before the vote is counted, written notice of such death or incapacity is received by this corporation. No proxy shall be valid after the expiration of eleven months from the date of its authorization unless otherwise provided in the proxy.

Section 12.Inspectors of Election.

In advance of any meeting of shareholders, the Board may appoint any persons other than nominees as inspectors of election to act at such meeting and any adjournment thereof. If inspectors of election are not so appointed, or if any persons so appointed fail to appear or refuse to act, the chairman of any such meeting may, and on the request of any shareholder or shareholder's proxy shall, make such appointments at the meeting. The number of inspectors shall be either one or three. If appointed at a meeting on the request of one or more shareholders or proxies, the majority of shares present shall determine whether one or three inspectors are to be appointed.

The duties of such inspectors shall be as prescribed by Section 707 (b) of the California General Corporation Law and shall include: determining the number of shares outstanding and the voting power of each, the shares represented at the meeting, the existence of a quorum, and the authenticity, validity and effect of proxies; receiving votes, ballots or consents; hearing and determining all challenges and questions in any way arising in connection with the right to vote; counting and tabulating all votes or consents; determining when the polls shall close; determining the result; and doing such acts as may be proper to conduct the election or vote with fairness to all shareholders. If there are three inspectors of election, the decision, act or certificate of a majority is effective in all respects as the decision, act or certificate of all. Any report or certificate made by the inspectors of election is prima facie evidence of the facts stated therein.

8

ARTICLE III

ARTICLE III - DIRECTORS

Section 1.Powers.

Subject to limitations of the Articles, of these Bylaws and of the California General Corporation Law relating to action required to be approved by the shareholders or by the outstanding shares, the business and affairs of the corporation shall be managed and all corporate powers shall be exercised by or under the direction of the Board. The Board may delegate the management of the day-to-day operation of the business of the corporation provided that the business and affairs of the corporation shall be managed and all corporate powers shall be exercised under the ultimate direction of the Board. Without prejudice to such general powers, but subject to the same limitations, it is hereby expressly declared that the Board shall have the following powers in addition to the other powers enumerated in these Bylaws:

(a)    To select and remove all the other officers, agents and employees of the corporation, prescribe the powers and duties for them as may not be inconsistent with law, with the Articles or these Bylaws, fix their compensation and require from them security for faithful service.

(b)    To conduct, manage and control the affairs and business of the corporation and to make such rules and regulations therefor not inconsistent with law, or with the Articles or these Bylaws, as they may deem best.

(c)    To adopt, make and use a corporate seal, and to prescribe the forms of certificates of stock, and to alter the form of such seal and of such certificates from time to time as in their judgment they may deem best.

(d)    To authorize the issuance of shares of stock of the corporation from time to time, upon such terms and for such consideration as may be lawful.

(e)    To borrow money and incur indebtedness for the purposes of the corporation, and to cause to be executed and delivered therefor, in the corporate name, promissory notes, bonds, debentures, deeds of trust, mortgages, pledges, hypothecations or other evidences of debt and securities therefor.

Section 2.Number of Directors.

The authorized number of directors shall be not less than nine nor more than seventeen until changed by amendment of the Articles or by a Bylaw duly adopted by the shareholders. The exact number of directors shall be fixed, within the limits specified, by the Board by adoption of a resolution or by the shareholders in the same manner provided in these Bylaws for the amendment thereof.

9

ARTICLE III

Section 3.Election and Term of Office.

The directors shall be elected at each annual meeting of the shareholders, subject to Article II, Section 7 of these Bylaws, but if any such annual meeting is not held or no vote is taken on the election of directors thereat, the directors may be elected at any special meeting of shareholders held for that purpose. Subject to Article II, Section 7 of these Bylaws, each director shall hold office until the next annual meeting and until a successor has been elected and qualified.

Section 4.Vacancies.

Any director may resign effective upon giving written notice to the Chairman of the Board, the President, the Secretary or the Board, unless the notice specifies a later time for the effectiveness of such resignation. If the resignation is effective at a future time, a successor may be elected to take office when the resignation becomes effective.

Vacancies in the Board, except those existing as a result of a removal of a director, may be filled by a majority of the remaining directors, though less than a quorum, or by a sole remaining director, and each director so elected shall hold office until the next annual meeting and, subject to Article II, Section 7 of these Bylaws, until such director's successor has been elected and qualified. Vacancies existing as a result of a removal of a director may be filled by the shareholders as provided by law. Any vacancy on the Board resulting from any expiration of the term of an incumbent director as provided in Article II, Section 7 of these Bylaws shall be deemed to have been created by resignation, and not removal, of the incumbent director.

A vacancy or vacancies in the Board shall be deemed to exist in case of the death, resignation or removal of any director, or if the authorized number of directors be increased, or if the shareholders fail, at any annual or special meeting of shareholders at which any director or directors are elected, to elect the full authorized number of directors to be voted for at that meeting.

The Board may declare vacant the office of a director who has been declared of unsound mind by an order of court or convicted of a felony.

The shareholders may elect a director or directors at any time to fill any vacancy or vacancies not filled by the directors. Any such election by written consent other than to fill a vacancy created by removal requires the consent of a majority of the outstanding shares entitled to vote.

No reduction of the authorized number of directors shall have the effect of removing any director prior to the expiration of the director's term of office.

10

ARTICLE III

Section 5.Place of Meeting.

Regular or special meetings of the Board shall be held at any place within or without the State of California which has been designated from time to time by the Board, specified in the notice of the meeting, or as otherwise provided in these Bylaws. In the absence of such designation, regular meetings shall be held at the principal office of the corporation.

Section 6.Organization Meeting.

Promptly following each annual meeting of shareholders the Board shall hold a regular meeting for the purpose of organization, election of officers and the transaction of other business.

Section 7.Special Meetings and Other Regular Meetings.

Special meetings and regular meetings other than organization meetings of the Board for any purpose or purposes may be called at any time by the Chairman of the Board, the President, any Vice President, the Secretary or by any two directors.

Such meetings of the Board shall be held upon four days' notice by mail or twenty-four hours' notice delivered personally or by telephone, including a voice messaging system or other system or technology designed to record and communicate messages, telegraph, telex, facsimile, electronic mail or other similar means of communication. Any such notice shall be addressed or delivered to each director at such director's address, telephone number, telex number, facsimile number, E-mail address, or other designated location(s), as shown upon the records of the corporation or as may have been given to the corporation by the director for purposes of notice or, if such information is not shown on such records or is not readily ascertainable, at the place in which the meetings of the directors are regularly held. The notice need not specify the purpose of such meeting.

Notice by mail shall be deemed to have been given at the time a written notice is deposited in the United States mail, postage prepaid. Any other written notice shall be deemed to have been given at the time it is personally delivered to the recipient or is delivered to a common carrier for transmission, or actually transmitted by the person giving the notice by electronic means to the recipient. Oral notice shall be deemed to have been given at the time it is communicated, in person or by telephone, wireless, or other similar means, to the recipient or to a person at the office of the recipient who the person giving the notice has reason to believe will promptly communicate it to the recipient, or actually transmitted to the recipient by the person giving the notice by a system or technology designed to record and communicate messages.

11

ARTICLE III

Section 8.Quorum.

One-third of the number of authorized directors constitutes a quorum of the Board for the transaction of business, except to adjourn as provided in Section ll of this Article. Every act or decision done or made by a majority of the directors present at a meeting duly held at which a quorum is present shall be regarded as the act of the Board, unless a greater number is required by law or by the Articles; provided, however, that a meeting at which a quorum is initially present may continue to transact business notwithstanding the withdrawal of directors, if any action taken is approved by at least a majority of the required quorum for such meeting.

Section 9.Participation in Meetings by Conference Telephone.

Members of the Board may participate in a meeting through use of conference telephone or similar communications equipment, so long as all members participating in such meeting can hear one another. Such participation constitutes presence in person at such meeting.

Section 10.Waiver of Notice.

The transactions of any meeting of the Board, however called and noticed or wherever held, are as valid as though had at a meeting duly held after regular call and notice if a quorum is present and if, either before or after the meeting, each of the directors not present signs a written waiver of notice, a consent to holding such meeting or an approval of the minutes thereof. All such waivers, consents or approvals shall be filed with the corporate records or made a part of the minutes of the meeting.

Section 11.Adjournment.

A majority of the directors present, whether or not a quorum is present, may adjourn any directors' meeting to another time and place. Notice of the time and place of holding an adjourned meeting need not be given to absent directors if the time and place is fixed at the meeting adjourned. If the meeting is adjourned for more than twenty-four hours, notice of any adjournment to another time or place shall be given prior to the time of the adjourned meeting to the directors who were not present at the time of the adjournment.

Section 12.Fees and Compensation.

Directors and members of committees may receive such compensation, if any, for their services, and such reimbursement for expenses, as may be fixed or determined by the Board.

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Section 13.Action Without Meeting.

Any action required or permitted to be taken by the Board may be taken without a meeting if all members of the Board shall individually or collectively consent in writing to such action. Such written consent or consents shall have the same force and effect as a unanimous vote of the Board and shall be filed with the minutes of the proceedings of the Board.

Section 14.Rights of Inspection.

Every director shall have the absolute right at any reasonable time to inspect and copy all books, records and documents of every kind and to inspect the physical properties of the corporation and also of its subsidiary corporations, domestic or foreign. Such inspection by a director may be made in person or by agent or attorney and includes the right to copy and make extracts.

Section 15.Committees.

The Board may appoint one or more committees, each consisting of two or more directors, to serve at the pleasure of the Board. The Board may delegate to such committees any or all of the authority of the Board except with respect to:

(a)    The approval of any action for which the California General Corporation Law also requires shareholders' approval or approval of the outstanding shares;

(b)    The filling of vacancies on the Board or in any committee;

(c)    The fixing of compensation of the directors for serving on the Board or on any committee;

(d)    The amendment or repeal of Bylaws or the adoption of new Bylaws;

(e)    The amendment or repeal of any resolution of the Board which by its express terms is not so amendable or repealable;

(f)    A distribution to the shareholders of the corporation except at a rate or in a periodic amount or within a price range determined by the Board; or

(g)    The appointment of other committees of the Board or the members thereof.

Any such committee, or any member or alternate member thereof, must be appointed by resolution adopted by a majority of the exact number of authorized directors

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ARTICLE III

as specified in Section 2 of this Article. The Board shall have the power to prescribe the manner and timing of giving of notice of regular or special meetings of any committee and the manner in which proceedings of any committee shall be conducted. In the absence of any such prescription, such committee shall have the power to prescribe the manner in which its proceedings shall be conducted. Unless the Board or such committee shall otherwise provide, the regular and special meetings and other actions of any such committee shall be governed by the provisions of this Article applicable to meetings and actions of the Board. Minutes shall be kept of each meeting of each committee.

ARTICLE IV - OFFICERS

Section 1.Officers.

The officers of the corporation shall be a Chairman of the Board, a President, a Chief Financial Officer, one or more Vice Presidents, a General Counsel and a Secretary. The corporation may also have, at the discretion of the Board, one or more Associate General Counsel, one or more Assistant General Counsel, a Controller, one or more Assistant Controllers, a Treasurer, one or more Assistant Treasurers and one or more Assistant Secretaries, and such other officers as may be elected or appointed in accordance with Section 5 of this Article. The Board, the Chairman of the Board or the President may confer a special title upon any Vice President not specified herein.

Section 2.Election.

The officers of the corporation, except such officers as may be elected or appointed in accordance with the provisions of Section 5 or Section 6 of this Article, shall be chosen annually by, and shall serve at the pleasure of the Board, and shall hold their respective offices until their resignation, removal, or other disqualification from service, or until their respective successors shall be elected.

Section 3.Eligibility of Chairman.

No person shall be eligible for the office of Chairman of the Board unless such person is a member of the Board of the corporation; any other officer may or may not be a director.

Section 4.Removal and Resignation.

Any officer may be removed, either with or without cause, by the Board at any time or by any officer upon whom such power of removal may be conferred by the Board. Any such removal shall be without prejudice to the rights, if any, of the officer under any contract of employment of the officer.

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ARTICLE IV

Any officer may resign at any time by giving written notice to the corporation, but without prejudice to the rights, if any, of the corporation under any contract to which the officer is a party. Any such resignation shall take effect at the date of the receipt of such notice or at any later time specified therein and, unless otherwise specified therein, the acceptance of such resignation shall not be necessary to make it effective.

Section 5.Appointment of Other Officers.

The Board may appoint such other officers as the business of the corporation may require, each of whom shall hold office for such period, have such authority, and perform such duties as are provided in the Bylaws or as the Board may from time to time determine.

Section 6.Vacancies.

A vacancy in any office because of death, resignation, removal, disqualification or any other cause shall be filled at any time deemed appropriate by the Board in the manner prescribed in these Bylaws for regular election or appointment to such office.

Section 7. Salaries.

The salaries of the Chairman of the Board, President, Chief Financial Officer, Vice Presidents, General Counsel, Controller, Treasurer and Secretary of the corporation shall be fixed by the Board. Salaries of all other officers shall be as approved from time to time by the chief executive officer.

Section 8.Furnish Security for Faithfulness.

Any officer or employee shall, if required by the Board, furnish to the corporation security for faithfulness to the extent and of the character that may be required.

Section 9. Chairman's Duties; Succession to Such Duties in Chairman's Absence or Disability.

The Chairman of the Board shall be the chief executive officer of the corporation and shall preside at all meetings of the shareholders and of the Board. Subject to the Board, the Chairman of the Board shall have charge of the business of the corporation. The Chairman of the Board shall keep the Board fully informed, and shall freely consult them concerning the business of the corporation.

In the absence or disability of the Chairman of the Board, the President shall act as the chief executive officer of the corporation; in the absence or disability of the Chairman

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ARTICLE IV

of the Board and the President, the next in order of election by the Board of the Vice Presidents shall act as chief executive officer of the corporation.

In the absence or disability of the Chairman of the Board, one of the following shall act, in the order indicated, as Chairman of the Board at meetings of the Board: first, any member of the Board who has been designated by the Board as a lead director; second, the President, if a member of the Board; third, a Vice President, if any, who is a member of the Board, in order of election; and, fourth, any member of the Board who is designated by the Board as a temporary Chairman to preside at any such meeting of the Board.

Section 10.President's Duties.

The President shall perform such other duties as the Chairman of the Board shall delegate or assign to such officer.

Section 11.Chief Financial Officer.

The Chief Financial Officer of the corporation shall be the chief consulting officer in all matters of financial import and shall have control over all financial matters concerning the corporation. If the corporation does not have a currently elected and acting Controller, the Chief Financial Officer shall also be the Chief Accounting Officer of the corporation.

Section 12.Vice Presidents' Duties.

The Vice Presidents shall perform such other duties as the chief executive officer shall designate.

Section 13.General Counsel's Duties.

The General Counsel shall be the chief consulting officer of the corporation in all legal matters and, subject to the chief executive officer, shall have control over all matters of legal import concerning the corporation.

Section 14. Associate General Counsel's and Assistant General Counsel's Duties.

The Associate General Counsel shall perform such of the duties of the General Counsel as the General Counsel shall designate, and in the absence or disability of the General Counsel, the Associate General Counsel, in order of election to that office by the Board at its latest organizational meeting, shall perform the duties of the General Counsel. The Assistant General Counsel shall perform such duties as the General Counsel shall designate.

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ARTICLE IV

Section 15.Controller's Duties.

The Controller shall be the chief accounting officer of the Corporation and, subject to the Chief Financial Officer, shall have control over all accounting matters concerning the Corporation and shall perform such other duties as the Chief Executive Officer shall designate.

Section 16.Assistant Controllers' Duties.

The Assistant Controllers shall perform such of the duties of the Controller as the Controller shall designate, and in the absence or disability of the Controller, the Assistant Controllers, in order of election to that office by the Board at its latest organizational meeting, shall perform the duties of the Controller.

Section 17.Treasurer's Duties.

It shall be the duty of the Treasurer to keep in custody or control all money, stocks, bonds, evidences of debt, securities and other items of value that may belong to, or be in the possession or control of, the corporation, and to dispose of the same in such manner as the Board or the chief executive officer may direct, and to perform all acts incident to the position of Treasurer.

Section 18.Assistant Treasurers' Duties.

The Assistant Treasurers shall perform such of the duties of the Treasurer as the Treasurer shall designate, and in the absence or disability of the Treasurer, the Assistant Treasurers, in order of election to that office by the Board at its latest organizational meeting, shall perform the duties of the Treasurer, unless action is taken by the Board as contemplated in Article IV, Section 22.

Section 19.Secretary's Duties.

The Secretary shall keep or cause to be kept full and complete records of the proceedings of shareholders, the Board and its committees at all meetings, and shall affix the corporate seal and attest by signing copies of any part thereof when required.

The Secretary shall keep, or cause to be kept, a copy of the Bylaws of the corporation at the principal office in accordance with Section 213 of the California General Corporation Law.

The Secretary shall be the custodian of the corporate seal and shall affix it to such instruments as may be required.

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ARTICLE IV

The Secretary shall keep on hand a supply of blank stock certificates of such forms as the Board may adopt.

The Secretary shall serve or cause to be served by publication or otherwise, as may be required, all notices of meetings and of other corporate acts that may by law or otherwise be required to be served, and shall make or cause to be made and filed in the principal office of the corporation, the necessary certificate or proofs thereof.

An affidavit of mailing of any notice of a shareholders' meeting or of any report, in accordance with the provisions of Section 60l (b) of the California General Corporation Law, executed by the Secretary shall be prima facie evidence of the fact that such notice or report had been duly given.

The Secretary may, with the Chairman of the Board, the President, or a Vice President, sign certificates of ownership of stock in the corporation, and shall cause all certificates so signed to be delivered to those entitled thereto.

The Secretary shall keep all records required by the California General Corporation Law.

The Secretary shall generally perform the duties usual to the office of secretary of corporations, and such other duties as the chief executive officer shall designate.

Section 20.Assistant Secretaries' Duties.

Assistant Secretaries shall perform such of the duties of the Secretary as the Secretary shall designate, and in the absence or disability of the Secretary, the Assistant Secretaries, in the order of election to that office by the Board at its latest organizational meeting, shall perform the duties of the Secretary, unless action is taken by the Board as contemplated in Article IV, Sections 21 and 22 of these Bylaws.

Section 21.Secretary Pro Tempore.

At any meeting of the Board or of the shareholders from which the Secretary is absent, a Secretary pro tempore may be appointed and act.

Section 22.Election of Acting Treasurer or Acting Secretary.

The Board may elect an Acting Treasurer, who shall perform all the duties of the Treasurer during the absence or disability of the Treasurer, and who shall hold office only for such a term as shall be determined by the Board.

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ARTICLE IV

The Board may elect an Acting Secretary, who shall perform all the duties of the Secretary during the absence or disability of the Secretary, and who shall hold office only for such a term as shall be determined by the Board.

Whenever the Board shall elect either an Acting Treasurer or Acting Secretary, or both, the officers of the corporation as set forth in Article IV, Section 1 of these Bylaws, shall include as if therein specifically set out, an Acting Treasurer or an Acting Secretary, or both.

Section 23.Performance of Duties.

Officers shall perform the duties of their respective offices as stated in these Bylaws, and such additional duties as the Board shall designate.

ARTICLE V - OTHER PROVISIONS

Section 1.Inspection of Corporate Records.

(a)    A shareholder or shareholders holding at least five percent in the aggregate of the outstanding voting shares of the corporation or who hold at least one percent of such voting shares and have filed a Schedule 14B with the United States Securities and Exchange Commission relating to the election of directors of the corporation shall have an absolute right to do either or both of the following:

(i)    Inspect and copy the record of shareholders' names and addresses and shareholdings during usual business hours upon five business days' prior written demand upon the corporation; or

(ii)    Obtain from the transfer agent, if any, for the corporation, upon five business days' prior written demand and upon the tender of its usual charges for such a list (the amount of which charges shall be stated to the shareholder by the transfer agent upon request), a list of the shareholders' names and addresses who are entitled to vote for the election of directors and their shareholdings, as of the most recent record date for which it has been compiled or as of a date specified by the shareholder subsequent to the date of demand.

(b)    The record of shareholders shall also be open to inspection and copying by any shareholder or holder of a voting trust certificate at any time during usual business hours upon written demand on the corporation, for a purpose reasonably related to such holder's interest as a shareholder or holder of a voting trust certificate.

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ARTICLE V

(c)    The accounting books and records and minutes of proceedings of the shareholders and the Board and committees of the Board shall be open to inspection upon written demand on the corporation of any shareholder or holder of a voting trust certificate at any reasonable time during usual business hours, for a purpose reasonably related to such holder's interests as a shareholder or as a holder of such voting trust certificate.

(d)    Any such inspection and copying under this Article may be made in person or by agent or attorney.

Section 2.Inspection of Bylaws.

The corporation shall keep in its principle office the original or a copy of these Bylaws as amended to date, which shall be open to inspection by shareholders at all reasonable times during office hours.

Section 3. Contracts and Other Instruments, Loans, Notes and Deposits of Funds.

The Chairman of the Board, the President, or a Vice President, either alone or with the Secretary or an Assistant Secretary, or the Secretary alone, shall execute in the name of the corporation such written instruments as may be authorized by the Board and, without special direction of the Board, such instruments as transactions of the ordinary business of the corporation may require and, such officers without the special direction of the Board may authenticate, attest or countersign any such instruments when deemed appropriate. The Board may authorize any person, persons, entity, entities, attorney, attorneys, attorney-in-fact, attorneys-in-fact, agent or agents, to enter into any contract or execute and deliver any instrument in the name of and on behalf of the corporation, and such authority may be general or confined to specific instances.

No loans shall be contracted on behalf of the corporation and no evidences of such indebtedness shall be issued in its name unless authorized by the Board as it may direct. Such authority may be general or confined to specific instances.

All checks, drafts, or other similar orders for the payment of money, notes, or other such evidences of indebtedness issued in the name of the corporation shall be signed by such officer or officers, agent or agents of the corporation and in such manner as the Board or chief executive officer may direct.

Unless authorized by the Board or these Bylaws, no officer, agent, employee or any other person or persons shall have any power or authority to bind the corporation by any contract or engagement or to pledge its credit or to render it liable for any purpose or amount.

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ARTICLE V

All funds of the corporation not otherwise employed shall be deposited from time to time to the credit of the corporation in such banks, trust companies, or other depositories as the Board may direct.

Section 4.Certificates of Stock and Uncertificated Stock.

Shares of the corporation's stock may be certificated or uncertificated, as provided under California law. All certificates of stock of the corporation shall be numbered and shall be entered in the books of the corporation as they are issued. Every certificate of stock of the corporation shall be signed in the name of the corporation by the Chairman of the Board, the President, or a Vice President and by the Chief Financial Officer, the Treasurer or an Assistant Treasurer or the Secretary or an Assistant Secretary, certifying the number of shares and the class or series of shares owned by the shareholder. Any or all of the signatures on the certificate may be facsimile. In case any officer, transfer agent or registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, transfer agent or registrar before such certificate is issued, it may be issued by the corporation with the same effect as if such person were an officer, transfer agent or registrar at the date of issue.

Certificates for shares and uncertificated shares may be used prior to full payment under such restrictions and for such purposes as the Board may provide; provided, however, that on any certificate issued to represent any partly paid shares, or, for uncertificated shares, on the initial transaction statement for such partly paid shares, the total amount of the consideration to be paid therefor and the amount paid thereon shall be stated.

Except as provided in this Section, no new certificate for shares and no uncertificated shares shall be issued in lieu of an old certificate unless the latter is surrendered and canceled at the same time. The Board may, however, if any certificate for shares is alleged to have been lost, stolen or destroyed, authorize the issuance of a new certificate or uncertificated shares in lieu thereof, and the corporation may require that the corporation be given a bond or other adequate security sufficient to indemnify it against any claim that may be made against it (including expense or liability) on account of the alleged loss, theft or destruction of such certificate or the issuance of such new certificate or uncertificated shares.

Transfers of shares of stock of the corporation shall be made on the books of the corporation only by the record holder of such stock, or by an attorney lawfully constituted in writing, and in the case of stock represented by a certificate, upon surrender of the certificate.

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ARTICLE V

Section 5.Transfer Agent, Transfer Clerk and Registrar.

The Board may, from time to time, appoint transfer agents, transfer clerks, and stock registrars to transfer and register the shares of capital stock of the corporation, and may provide that no certificate of capital stock shall be valid without the signature of the stock transfer agent or transfer clerk, and stock registrar.

Section 6.Representation of Shares of Other Corporations.

The chief executive officer or any other officer or officers authorized by the Board or the chief executive officer are each authorized to vote, represent and exercise on behalf of the corporation all rights incident to any and all shares of any other corporation or corporations standing in the name of the corporation. The authority herein granted may be exercised either by any such officer in person or by any other person authorized so to do by proxy or power of attorney duly executed by said officer.

Section 7.Stock Purchase Plans.

The corporation may adopt and carry out a stock purchase plan or agreement or stock option plan or agreement providing for the issue and sale for such consideration as may be fixed of its unissued shares, or of issued shares acquired, to one or more of the employees or directors of the corporation or of a subsidiary or to a trustee on their behalf and for the payment for such shares in installments or at one time, and may provide for such shares in installments or at one time, and may provide for aiding any such persons in paying for such shares by compensation for services rendered, promissory notes or otherwise.

Any such stock purchase plan or agreement or stock option plan or agreement may include, among other features, the fixing of eligibility for participation therein, the class and price of shares to be issued or sold under the plan or agreement, the number of shares which may be subscribed for, the method of payment therefor, the reservation of title until full payment therefor, the effect of the termination of employment and option or obligation on the part of the corporation to repurchase the shares upon termination of employment, restrictions upon transfer of the shares, the time limits of and termination of the plan, and any other matters, not in violation of applicable law, as may be included in the plan as approved or authorized by the Board or any committee of the Board.

Section 8.Fiscal Year and Subdivisions.

The calendar year shall be the corporate fiscal year of the corporation. For the purpose of paying dividends, for making reports and for the convenient transaction of the business of the corporation, the Board may divide the fiscal year into appropriate subdivisions.

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ARTICLE V

Section 9.Construction and Definitions.

Unless the context otherwise requires, the general provisions, rules of construction and definitions contained in the General Provisions of the California Corporations Code and in the California General Corporation Law shall govern the construction of these Bylaws.

ARTICLE VI - INDEMNIFICATION

Section 1.Indemnification of Directors and Officers.

Each person who was or is a party or is threatened to be made a party to or is involved in any threatened, pending or completed action, suit or proceeding, formal or informal, whether brought in the name of the corporation or otherwise and whether of a civil, criminal, administrative or investigative nature (hereinafter a "proceeding"), by reason of the fact that he or she, or a person of whom he or she is the legal representative, is or was a director or officer of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to employee benefit plans, whether the basis of such proceeding is an alleged action or inaction in an official capacity or in any other capacity while serving as a director or officer, shall, subject to the terms of any agreement between the corporation and such person, be indemnified and held harmless by the corporation to the fullest extent permissible under California law and the corporation's Articles of Incorporation, against all costs, charges, expenses, liabilities and losses (including attorneys' fees, judgments, fines, ERISA excise taxes or penalties and amounts paid or to be paid in settlement) reasonably incurred or suffered by such person in connection therewith, and such indemnification shall continue as to a person who has ceased to be a director or officer and shall inure to the benefit of his or her heirs, executors and administrators; provided, however, that (A) the corporation shall indemnify any such person seeking indemnification in connection with a proceeding (or part thereof) initiated by such person only if such proceeding (or part thereof) was authorized by the Board of the corporation; (B) the corporation shall indemnify any such person seeking indemnification in connection with a proceeding (or part thereof) other than a proceeding by or in the name of the corporation to procure a judgment in its favor only if any settlement of such a proceeding is approved in writing by the corporation; (C) that no such person shall be indemnified (i) except to the extent that the aggregate of losses to be indemnified exceeds the amount of such losses for which the director or officer is paid pursuant to any directors' and officers' liability insurance policy maintained by the corporation; (ii) on account of any suit in which judgment is rendered against such person for an accounting of profits made from the purchase or sale by such person of securities of the corporation pursuant to the provisions of Section 16(b) of the Securities Exchange Act of 1934 and

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ARTICLE VI

amendments thereto or similar provisions of any federal, state or local statutory law; (iii) if a court of competent jurisdiction finally determines that any indemnification hereunder is unlawful; and (iv) as to circumstances in which indemnity is expressly prohibited by Section 317 of the General Corporation Law of California (the "Law"); and (D) that no such person shall be indemnified with regard to any action brought by or in the right of the corporation for breach of duty to the corporation and its shareholders (a) for acts or omissions involving intentional misconduct or knowing and culpable violation of law; (b) for acts or omissions that the director or officer believes to be contrary to the best interests of the corporation or its shareholders or that involve the absence of good faith on the part of the director or officer; (c) for any transaction from which the director or officer derived an improper personal benefit; (d) for acts or omissions that show a reckless disregard for the director's or officer's duty to the corporation or its shareholders in circumstances in which the director or officer was aware, or should have been aware, in the ordinary course of performing his or her duties, of a risk of serious injury to the corporation or its shareholders; (e) for acts or omissions that constitute an unexcused pattern of inattention that amounts to an abdication of the director's or officer's duties to the corporation or its shareholders; and (f) for costs, charges, expenses, liabilities and losses arising under Section 310 or 316 of the Law. The right to indemnification conferred in this Article shall include the right to be paid by the corporation expenses incurred in defending any proceeding in advance of its final disposition; provided, however, that if the Law permits the payment of such expenses incurred by a director or officer in his or her capacity as a director or officer (and not in any other capacity in which service was or is rendered by such person while a director or officer, including, without limitation, service to an employee benefit plan) in advance of the final disposition of a proceeding, such advances shall be made only upon delivery to the corporation of an undertaking, by or on behalf of such director or officer, to repay all amounts to the corporation if it shall be ultimately determined that such person is not entitled to be indemnified.

Section 2.Indemnification of Employees and Agents.

A person who was or is a party or is threatened to be made a party to or is involved in any proceeding by reason of the fact that he or she is or was an employee or agent of the corporation or is or was serving at the request of the corporation as an employee or agent of another enterprise, including service with respect to employee benefit plans, whether the basis of such action is an alleged action or inaction in an official capacity or in any other capacity while serving as an employee or agent, may, subject to the terms of any agreement between the corporation and such person, be indemnified and held harmless by the corporation to the fullest extent permitted by California law and the corporation's Articles of Incorporation, against all costs, charges, expenses, liabilities and losses, (including attorneys' fees, judgments, fines, ERISA excise taxes or penalties and amounts paid or to be paid in settlement) reasonably incurred or suffered by such person in connection therewith.

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ARTICLE VI

Section 3.Right of Directors and Officers to Bring Suit.

If a claim under Section 1 of this Article is not paid in full by the corporation within 30 days after a written claim has been received by the corporation, the claimant may at any time thereafter bring suit against the corporation to recover the unpaid amount of the claim and, if successful in whole or in part, the claimant shall also be entitled to be paid the expense of prosecuting such claim. Neither the failure of the corporation (including its Board, independent legal counsel, or its shareholders) to have made a determination prior to the commencement of such action that indemnification of the claimant is permissible in the circumstances because he or she has met the applicable standard of conduct, if any, nor an actual determination by the corporation (including its Board, independent legal counsel, or its shareholders) that the claimant has not met the applicable standard of conduct, shall be a defense to the action or create a presumption for the purpose of an action that the claimant has not met the applicable standard of conduct.

Section 4.Successful Defense.

Notwithstanding any other provision of this Article, to the extent that a director or officer has been successful on the merits or otherwise (including the dismissal of an action without prejudice or the settlement of a proceeding or action without admission of liability) in defense of any proceeding referred to in Section 1 or in defense of any claim, issue or matter therein, he or she shall be indemnified against expenses (including attorneys' fees) actually and reasonably incurred in connection therewith.

Section 5.Non-Exclusivity of Rights.

The right to indemnification provided by this Article shall not be exclusive of any other right which any person may have or hereafter acquire under any statute, bylaw, agreement, vote of shareholders or disinterested directors or otherwise.

Section 6.Insurance.

The corporation may maintain insurance, at its expense, to protect itself and any director, officer, employee or agent of the corporation or another corporation, partnership, joint venture, trust or other enterprise against any expense, liability or loss, whether or not the corporation would have the power to indemnify such person against such expense, liability or loss under the Law.

Section 7.Expenses as a Witness.

To the extent that any director, officer, employee or agent of the corporation is by reason of such position, or a position with another entity at the request of the corporation,

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ARTICLE VI

a witness in any action, suit or proceeding, he or she shall be indemnified against all costs and expenses actually and reasonably incurred by him or her on his or her behalf in connection therewith.

Section 8.Indemnity Agreements.

The corporation may enter into agreements with any director, officer, employee or agent of the corporation providing for indemnification to the fullest extent permissible under the Law and the corporation's Articles of Incorporation.

Section 9.Separability.

Each and every paragraph, sentence, term and provision of this Article is separate and distinct so that if any paragraph, sentence, term or provision hereof shall be held to be invalid or unenforceable for any reason, such invalidity or unenforceability shall not affect the validity or enforceability of any other paragraph, sentence, term or provision hereof. To the extent required, any paragraph, sentence, term or provision of this Article may be modified by a court of competent jurisdiction to preserve its validity and to provide the claimant with, subject to the limitations set forth in this Article and any agreement between the corporation and claimant, the broadest possible indemnification permitted under applicable law.

Section 10.Effect of Repeal or Modification.

Any repeal or modification of this Article shall not adversely affect any right of indemnification of a director or officer existing at the time of such repeal or modification with respect to any action or omission occurring prior to such repeal or modification.

ARTICLE VII - EMERGENCY PROVISIONS

Section 1.General.

The provisions of this Article shall be operative only during a national emergency declared by the President of the United States or the person performing the President's functions, or in the event of a nuclear, atomic or other attack on the United States or on a locality in which the corporation conducts its business or customarily holds meetings of its Board of Directors or shareholders, or during the existence of any catastrophe, disaster or other similar emergency condition.

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ARTICLE VII

Section 2.Notice of Meetings.

Special meetings and regular meetings of the Board may be held upon one hour's notice delivered in any manner permitted in Article III, Section 7 of these Bylaws.

Section 3.Quorum.

The number of directors necessary to constitute a quorum shall be one‑third of the authorized number of directors, or such other minimum number required by law or lawful decree then in force, whichever number is less.

ARTICLE VIII - AMENDMENTS

Section 1.Amendments.

These Bylaws may be amended or repealed either by approval of the outstanding shares or by the approval of the Board; provided, however, that a Bylaw specifying or changing a fixed number of directors or the maximum or minimum number or changing from a fixed to a variable Board or vice versa may only be adopted by approval of the outstanding shares. The exact number of directors within the maximum and minimum number specified in these Bylaws may be amended by the Board alone.

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EX-31.1

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 September 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 (asdefined 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 arereasonably 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: November  2, 2011

/s/ THEODORE F. CRAVER, JR.

THEODORE F. CRAVER, JR.

Chief Executive Officer

EX-31.2

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 September 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: November 2, 2011

/s/ W. JAMES SCILACCI

W. JAMES SCILACCI

Chief Financial Officer

EX-32

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 September 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: November 2, 2011

/s/ THEODORE F. CRAVER, JR.

THEODORE F. CRAVER, JR.

Chief Executive Officer

Edison International

/s/ W. JAMES SCILACCI

W. JAMES SCILACCI

Chief Financial Officer

Edison International

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

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

XML

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Effective Tax Rate
Income from continuing operations before income taxes	$ 683	$ 774			$ 1,217	$ 1,386
Federal statutory rate (as a percent)	35.00%	35.00%			35.00%	35.00%
Provision for income tax at federal statutory rate	239	271			426	485
Items presented with related state income tax, net
Global Settlement related	0	(37)	138		0	(175)
Change in tax accounting method for asset removal costs	0	0	(40)		0	(40)
State tax - net of federal benefit	30	34			43	57
Health care legislation	0	0			0	39
Production and housing credits	(12)	(14)			(48)	(48)
Property-related and other	(15)	(7)			(52)	(57)
Total income tax expense from continuing operations	242	247			369	261
Effective tax rate (as a percent)	35.00%	32.00%			30.00%	19.00%
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)
Unrecognized Tax Benefits
Unrecognized tax benefits, beginning balance				664	565	664
Unrecognized tax benefits, increases resulting from current period tax positions					53	60
Unrecognized tax benefits, increases resulting from prior period tax positions					60	251
Unrecognized tax benefits, decreases resulting from prior period tax positions					(37)	(86)
Unrecognized tax benefits, decreases resulting from settlements with taxing authorities						(82)
Unrecognized tax benefits, ending balance	641	807			641	807
Unrecognized tax benefits that would impact effective tax rate	500				500		455
Accrued Interest and Penalties
Accrued interest and penalties	230				230		213
Net after-tax interest income and penalties recognized in income tax expense (benefit)	5	(7)			10	(95)
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	92				92
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	$ 191				$ 191
Penalty for understatement of tax liability (as a percent)					40.00%

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Consolidated Statements of Comprehensive Income (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Net income	$ 441	$ 523	$ 845	$ 1,129
Pension and postretirement benefits other than pensions:
Net gain arising during the period, net of income tax expense of $2 for the nine months ended September 30, 2010	0	1	0	13
Amortization of net (gain) loss included in net income, net of income tax expense (benefit) of $1 and $1 for the three months and $4 and $(3) for the nine months ended September 30, 2011 and 2010, respectively	3	1	7	(5)
Prior service credit arising during the period, net of income tax expense of $1 for the nine months ended September 30, 2010	0	0	0	2
Amortization of prior service credit, net of income tax benefit of $1 for the nine months ended September 30, 2010	0	0	0	(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 $(19) and $29 for the three months and $(24) and $41 for the nine months ended September 30, 2011 and 2010, respectively	(30)	43	(38)	61
Reclassification adjustments included in net loss, net of income tax benefit of none and $5 for the three months and $12 and $54 for the nine months ended September 30, 2011 and 2010, respectively	0	(7)	(17)	(80)
Other comprehensive income (loss)	(27)	38	(48)	(11)
Comprehensive income	414	561	797	1,118
Less: Comprehensive income attributable to noncontrolling interests	15	13	43	39
Comprehensive income attributable to Edison International	$ 399	$ 548	$ 754	$ 1,079

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Net gain arising during the period, income tax expense	$ 0	$ 0	$ 0	$ 2
Amortization of net (gain) loss included in net income, income tax expense (benefit)	1	1	4	(3)
Prior service credit arising during the period, income tax expense	0	0	0	1
Amortization of prior service credit, income tax benefit	0	0	0	(1)
Unrealized holding gain (loss) arising during the period, income tax expense (benefit)	(19)	29	(24)	41
Reclassification adjustments included in net income, income tax benefit	$ 0	$ 5	$ 12	$ 54

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Commitments and Contingencies (Details) (USD $)	1 Months Ended		9 Months Ended			6 Months Ended	0 Months Ended			9 Months Ended	0 Months Ended
	Oct. 30, 2011 Southern California Edison Company New Contract [Member] Purchased power	Oct. 30, 2011 Edison Mission Group Inc. New Contract [Member] Turbine commitments	Sep. 30, 2011 Southern California Edison Company Transmission Agreement [Member]	Sep. 30, 2011 Southern California Edison Company Environmental Indemnities	Sep. 30, 2011 Southern California Edison Company Operating Leases - Purchase Power Contracts	Jun. 30, 2011 Edison Mission Group Inc. Turbine commitments	Oct. 08, 2010 Edison Mission Group Inc. Mitsubishi Power Systems Americans, Inc. and Mitsubishi Heavy Industries, Ltd. mW	Sep. 30, 2011 Edison Mission Group Inc. Capital Expenditures	Sep. 30, 2011 Edison Mission Energy Indemnities under International Asset Sale Agreements	Sep. 30, 2011 Midwest Generation and EME Homer City Generation L.P. (Homer City) Purchase of fuel and transportation of gas and coal	Feb. 20, 2003 Midwest Generation LLC. Environmental Indemnities under Acquisition Agreement	Sep. 30, 2011 Midwest Generation LLC. Environmental Indemnities under Acquisition Agreement
Third-Party Power Purchase Agreements
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
Subsequent Long-term Purchase Commitment Amount Year One	5,000,000
Subsequent Long-term Purchase Commitment Amount Year Two	81,000,000
Subsequent Long-term Purchase Commitment Amount Year Three	178,000,000
Subsequent Long-term Purchase Commitment Amount Year Four	240,000,000
Other Commitments
Purchase commitments, remainder of 2011			1,000,000							245,000,000
Purchase commitments, 2012			4,000,000							332,000,000
Purchase commitments, 2013			4,000,000							198,000,000
Purchase commitments, 2014			4,000,000							150,000,000
Purchase commitments, 2015			4,000,000
Purchase commitments, Thereafter			78,000,000
Purchase commitments, aggregate										925,000,000
Turbine Commitments
Charges for default of termination of turbine commitments						29,000,000
Long-term Purchase Commitment, Amount		39,000,000
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 Commitments
Wind turbine payment commitments in remainder of 2011								157,000,000
Wind turbine payment commitments in 2012								235,000,000
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												230
Liability under indemnities									43,000,000			55,000,000
Maximum liability under indemnity per Mountainview purchase agreement for damages and other amounts				$ 60,000,000

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Other Income and Expenses

9 Months Ended

Sep. 30, 2011

Other Income and Expenses [Abstract]

Other Income and Expenses

Other Income and Expenses

Other income and expenses are as follows:

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2011		2010		2011		2010
Other income:
Equity Available Funds Used During Construction	$	18	$	24	$	74	$	76
Increase in cash surrender value of life insurance policies	6		7		19		19
Other	2		2		10		8
Total utility other income	26		33		103		103
Competitive power generation and other income	1		—		7		—
Total other income	$	27	$	33	$	110	$	103
Other expenses:
Civic, political and related activities and donations	$	6	$	7	$	21	$	21
Other	4		3		14		18
Total utility other expenses	10		10		35		39
Competitive power generation and other expenses	1		2		2		—
Total other expenses	$	11	$	12	$	37	$	39

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2011	Oct. 31, 2011
Document And Entity Information [Abstract]
Entity Registrant Name	EDISON INTERNATIONAL
Entity Central Index Key	0000827052
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		325,811,206

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Derivative Instruments and Hedging Activities (Details 2)	Sep. 30, 2011	Dec. 31, 2010
Electric Utility | Electricity options, swaps and forwards in gigawatts per hour (GWh) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	30,143	32,138
Electric Utility | Natural gas options, swaps and forwards, Bcf | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	266	250
Electric Utility | CRRs | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	146,628	181,291
Electric Utility | Tolling arrangements (GWh) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	104,822	114,599
Competitive power generation | Electricity Forwards/Futures, Sales, GWh | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	15,910	16,799
Competitive power generation | Electricity Forwards/Futures, Sales, GWh | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	13,353	22,456
Competitive power generation | Electricity Forwards/Futures, Sales, GWh | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	36,597	34,630
Competitive power generation | Electricity Forwards/Futures, Purchases, GWh | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	101	408
Competitive power generation | Electricity Forwards/Futures, Purchases, GWh | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	13,230	22,931
Competitive power generation | Electricity Forwards/Futures, Purchases, GWh | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	42,429	37,669
Competitive power generation | Electricity Capacity, Sales, MW-Day (in thousands) | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	134,000	190,000
Competitive power generation | Electricity Capacity, Sales, MW-Day (in thousands) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Electricity Capacity, Sales, MW-Day (in thousands) | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	12,000	136,000
Competitive power generation | Electricity Capacity, Purchases, MW-Day (in thousands) | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	12,000	8,000
Competitive power generation | Electricity Capacity, Purchases, MW-Day (in thousands) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Electricity Capacity, Purchases, MW-Day (in thousands) | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	219,000	419,000
Competitive power generation | Electricity Congestion, Sales, GWh | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Electricity Congestion, Sales, GWh | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	90	136
Competitive power generation | Electricity Congestion, Sales, GWh | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	15,910	12,020
Competitive power generation | Electricity Congestion, Purchases, GWh | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Electricity Congestion, Purchases, GWh | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	4,023	1,143
Competitive power generation | Electricity Congestion, Purchases, GWh | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	253,688	187,689
Competitive power generation | Natural Gas Forwards/Futures, Sales, billion cubic feet | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Natural Gas Forwards/Futures, Sales, billion cubic feet | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Natural Gas Forwards/Futures, Sales, billion cubic feet | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	55.3	30.6
Competitive power generation | Natural Gas Forwards/Futures, Purchases, billion cubic feet | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Natural Gas Forwards/Futures, Purchases, billion cubic feet | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Natural Gas Forwards/Futures, Purchases, billion cubic feet | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	53.4	34.3
Competitive power generation | Fuel Oil Forwards/Futures, Sales, Barrels | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Fuel Oil Forwards/Futures, Sales, Barrels | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0	250,000
Competitive power generation | Fuel Oil Forwards/Futures, Sales, Barrels | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	100,000	10,000
Competitive power generation | Fuel Oil Forwards/Futures, Purchases, Barrels | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments		0
Competitive power generation | Fuel Oil Forwards/Futures, Purchases, Barrels | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	240,000	490,000
Competitive power generation | Fuel Oil Forwards/Futures, Purchases, Barrels | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	140,000	10,000
Competitive power generation | Coal Forwards/Futures, Sales, tons | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Coal Forwards/Futures, Sales, tons | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Coal Forwards/Futures, Sales, tons | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	1,485,000	2,630,500
Competitive power generation | Coal Forwards/Futures, Purchases, tons | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Coal Forwards/Futures, Purchases, tons | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0	0
Competitive power generation | Coal Forwards/Futures, Purchases, tons | Trading Activities [Member]
Derivatives
Notional Volumes of Derivative Instruments	1,485,000	2,645,500
Competitive power generation | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2011

Accounting Policies [Abstract]

Inventory Components

(in millions)	September 30, 2011		December 31, 2010
Coal, gas, fuel oil and other raw materials	$	191	$	184
Spare parts, materials and supplies	401		384
Total inventory	$	592	$	568

EPS computation

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

	Three months ended September 30,					Nine months ended September 30,
(in millions)	2011		2010			2011		2010
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	426	$	514		$	805	$	1,086
Participating securities dividends	—		(3		)	—		(5		)
Income from continuing operations available to common shareholders	$	426	$	511		$	805	$	1,081
Weighted average common shares outstanding	326		326			326		326
Basic earnings per share – continuing operations	$	1.31	$	1.57		$	2.47	$	3.32
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	426	$	511		$	805	$	1,081
Income impact of assumed conversions	1		2			3		3
Income from continuing operations available to common shareholders and assumed conversions	$	427	$	513		$	808	$	1,084
Weighted average common shares outstanding	326		326			326		326
Incremental shares from assumed conversions	3		2			3		2
Adjusted weighted average shares – diluted	329		328			329		328
Diluted earnings per share – continuing operations	$	1.30	$	1.57		$	2.46	$	3.30

XML

Derivative Instruments and Hedging Activities (Details) (USD $) In Millions																	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended				3 Months Ended		9 Months Ended				9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Electric Utility Commodity contracts	Dec. 31, 2010 Electric Utility Commodity contracts	Sep. 30, 2011 Electric Utility Commodity contracts Economic hedges	Dec. 31, 2010 Electric Utility Commodity contracts Economic hedges	Sep. 30, 2011 Electric Utility Commodity contracts Netting and Collateral	Dec. 31, 2010 Electric Utility Commodity contracts Netting and Collateral	Sep. 30, 2011 Competitive power generation	Dec. 31, 2010 Competitive power generation	Sep. 30, 2011 Competitive power generation Trading and Non-trading activities	Dec. 31, 2010 Competitive power generation Trading and Non-trading activities	Sep. 30, 2011 Competitive power generation Cash flow hedges	Dec. 31, 2010 Competitive power generation Cash flow hedges	Sep. 30, 2011 Competitive power generation Economic hedges	Dec. 31, 2010 Competitive power generation Economic hedges	Sep. 30, 2011 Competitive power generation Economic hedges Competitive power generation revenues	Sep. 30, 2010 Competitive power generation Economic hedges Competitive power generation revenues	Sep. 30, 2011 Competitive power generation Economic hedges Competitive power generation revenues	Sep. 30, 2010 Competitive power generation Economic hedges Competitive power generation revenues	Sep. 30, 2011 Competitive power generation Economic hedges Fuel	Sep. 30, 2010 Competitive power generation Economic hedges Fuel	Sep. 30, 2011 Competitive power generation Economic hedges Fuel	Sep. 30, 2010 Competitive power generation Economic hedges Fuel	Sep. 30, 2011 Competitive power generation Trading activities	Dec. 31, 2010 Competitive power generation Trading activities	Sep. 30, 2011 Competitive power generation Trading activities Operating revenues	Sep. 30, 2010 Competitive power generation Trading activities Operating revenues	Sep. 30, 2011 Competitive power generation Trading activities Operating revenues	Sep. 30, 2010 Competitive power generation Trading activities Operating revenues	Sep. 30, 2011 Competitive power generation Netting and Collateral	Dec. 31, 2010 Competitive power generation Netting and Collateral	Sep. 30, 2011 Cash flow hedges Competitive power generation revenues	Sep. 30, 2010 Cash flow hedges Competitive power generation revenues	Dec. 31, 2010 Cash flow hedges Competitive power generation revenues	Dec. 31, 2009 Cash flow hedges Competitive power generation revenues
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	$ 100	$ 133	$ 68	$ 87	$ 82	$ 87	$ 14		$ 32	$ 46	$ 195	$ 315	$ 34	$ 54	$ 29	$ 77									$ 132	$ 184					$ (163)	$ (269)
Long-Term, Derivative Assets	191	437	132	367	145	367	13		59	70	113	107	8	2	3	2									102	103					(54)	(37)
Derivative Assets, Total			200	454	227	454	27		91	116	308	422	42	56	32	79									234	287					(217)	(306)
Short-Term, Derivative Liabilities	290	217	287	212	305	216	18	4	3	6	143	229	16	10	31	71									96	148					(140)	(223)
Long-Term, Derivative Liabilities	344	468	554	449	577	449	23		80	19	129	54	90	25	2	0									37	29					(49)	(35)
Derivative Liabilities, Total			841	661	882	665	41	4	83	25	272	283	106	35	33	71									133	177					(189)	(258)
Net Asset (Liability)			(641)	(207)	(655)	(211)	(14)	(4)	8	91	36	139	(64)	21	(1)	8									101	110					(28)	(48)
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net																																	(62)	102
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net																																	(29)	(134)
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges Effect Pretax																																	(64)	143	27	175
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net																	$ (6)	$ 7	$ 20	$ 0	$ (3)	$ 2	$ 1	$ 0			$ 11	$ 28	$ 68	$ 108

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Debt and Credit Agreements

9 Months Ended

Sep. 30, 2011

Debt Disclosure [Abstract]

Debt and Credit Agreements

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 October 2011, SCE issued $150 million of floating rate first and refunding mortgage bonds due in 2014. The proceeds from these bonds were used to finance fuel inventories.

In May 2011 and September 2011, SCE purchased $56 million and $30 million, respectively, of its variable rate tax-exempt bonds.

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 floating rate construction loans totaling $495 million that will convert to 10-year amortizing term loans by June 30, 2013, subject to meeting specified conditions, and also included $122 million of letter of credit ($40 million outstanding at September 30, 2011) and working capital facilities.

The non-recourse financings were completed in two parts. A construction plus term loan financing of $442 million that initially accrues interest at the London Interbank Offered Rate (LIBOR) plus 2.25% and increases by 0.25% after the third, sixth and ninth anniversaries of the term conversion date. An interest rate swap agreement for a portion of the construction loan fixed the floating rate at 0.81% beginning November 30, 2011 through March 31, 2013. The effective rate for the outstanding loan of $44 million was 2.48% at September 30, 2011. Under the swap agreement for majority of the term loan, the fixed interest rate will be 3.54% beginning June 28, 2013 through May 31, 2023 and the effective rate is expected to be 5.84%.

A second construction plus term loan financing of $53 million was obtained by a holding company that accrues interest at LIBOR plus 4.00% over the entire term. An interest rate swap agreement for a portion of the construction loan fixed the floating rate at 0.79% beginning July 29, 2011 through May 31, 2013. The effective rate for the outstanding loan of $49 million was 4.94% at September 30, 2011. Under the swap agreement for the majority of the term loan, the fixed interest rate will be 4.00% beginning June 28, 2013 through May 31, 2023 and the effective rate is expected to be 8.00%, Both outstanding loans were recorded in long-term debt on Edison International's consolidated balance sheet at September 30, 2011.

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 millionten-year term loan (expiring in December 2020), a $23 millionseven-year letter of credit facility and a $5 millionseven-year working capital facility. At September 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 September 30, 2011, SCE's outstanding short-term debt was $550 million at a weighted-average interest rate of 0.34%. 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 September 30, 2011, letters of credit issued under SCE's credit facilities aggregated $83 million and are scheduled to expire in twelve months or less.

At September 30, 2011, Edison International (Parent)'s outstanding short-term debt was $10 million at a weighted-average interest rate of 0.60%. 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 September 30, 2011, standby letters of credit under EME's credit facility aggregated $65 million and were scheduled to expire as follows: $1 million in 2011 and $64 million in 2012. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $98 million and were scheduled to expire as follows: $7 million in 2011, $63 million in 2012, $10 million in 2017, and $18 million in 2018.

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Consolidated Statements of Changes in Equity (Tables)

9 Months Ended

Sep. 30, 2011

Stockholders' Equity Note [Abstract]

Changes in equity

The following table provides the changes in equity for the nine months ended September 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 (loss)	—			—			802			802			(1		)	44			845
Other comprehensive loss	—			(48		)	—			(48		)	—			—			(48		)
Common stock dividends declared ($0.96 per share)	—			—			(313		)	(313		)	—			—			(313		)
Dividends, distributions to noncontrolling interests and other	—			—			—			—			(1		)	(44		)	(45		)
Stock-based compensation and other	7			—			(21		)	(14		)	—			—			(14		)
Noncash stock-based compensation and other	22			—			(3		)	19			—			(1		)	18
Purchase of noncontrolling interests1	(14		)	—			—			(14		)	—			—			(14		)
Issuance of preference stock	—			—			—			—			—			123			123
Balance at September 30, 2011	$	2,346		$	(124	)	$	8,793		$	11,015		$	2		$	1,029		$	12,046

¹  During the nine months ended September 30, 2011, EMG purchased the remaining interests in Pinnacle Wind Force, LLC, and Broken Bow I, LLC and all assets of the Crofton Bluffs project. All three projects are now 100% owned by EMG. The purchases of the noncontrolling interests were accounted for as equity transactions between controlling and noncontrolling interest holders.

The following table provides the changes in equity for the nine months ended September 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	—		—			1,090			1,090			—			39			1,129
Other comprehensive loss	—		(11		)	—			(11		)	—			—			(11		)
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 ($0.945 per share)	—		—			(308		)	(308		)	—			—			(308		)
Dividends, distributions to noncontrolling interests and other	—		—			—			—			(4		)	(39		)	(43		)
Stock-based compensation and other	5		—			(12		)	(7		)	—			—			(7		)
Noncash stock-based compensation and other	16		—			(2		)	14			—			—			14
Balance at September 30, 2010	$	2,325	$	26		$	8,283		$	10,634		$	5		$	907		$	11,546

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Variable Interest Entities (Details 2) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Maximum [Member] | Variable Interest Entity Not Primary Beneficiary Holds Significant Interest [Member] | EMG Domestic Energy Projects
Details of projects or entities
Equity Interest in Domestic Energy Projects (less than as a percent)	100.00%
Variable Interest Entity, Primary Beneficiary [Member] | EMG Wind Projects
Details of projects or entities
Number of projects	13	14
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 and the Sunrise project
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	64
Indebtedness of projects accounted for under equity method, amount proportionate to ownership interest	16
Variable Interest Entity, Deconsolidated | EMG Domestic Energy Projects
Details of projects or entities
Number of projects	5	5
Variable Interest Entity, Deconsolidated | EMG Wind Projects
Details of projects or entities
Interests in number of wind projects	3	2
EMG Natural Gas-Fired Projects
Details of projects or entities
Investment	340
Maximum Exposure, Total	340
EMG Renewable energy projects
Details of projects or entities
Investment	228
Maximum Exposure, Total	228

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Business Segments (Tables)

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Segment income statement information

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Operating Revenue:
Electric utility	$	3,386		$	3,098		$	8,063		$	7,504
Competitive power generation	596			691			1,686			1,838
Parent and other2	(1		)	(1		)	(3		)	(2		)
Consolidated Edison International	$	3,981		$	3,788		$	9,746		$	9,340
Net Income (Loss) attributable to Edison International:
Electric utility	$	406		$	394		$	838		$	858
Competitive power generation1	33			110			(17		)	214
Parent and other2	(13		)	6			(19		)	18
Consolidated Edison International	$	426		$	510		$	802		$	1,090

Segment balance sheet information

(in millions)	September 30, 2011			December 31, 2010
Total Assets:
Electric utility	$	38,122		$	35,906
Competitive power generation	9,881			9,597
Parent and other2	(331		)	27
Consolidated Edison International	$	47,672		$	45,530

¹ Includes earnings (losses) from discontinued operations of none and $(4) million for the three months ended September 30, 2011 and 2010, respectively, and $(3) million and $4 million for the nine months ended September 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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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2011

Accounting Policies [Abstract]

Cash Equivalents

Cash Equivalents

Cash equivalents included investments in money market funds totaling $1.1 billion at both September 30, 2011 and December 31, 2010. Generally, the carrying value of cash equivalents equals the fair value, as these 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 $215 million and $197 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at September 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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Regulatory and Environmental Developments

9 Months Ended

Sep. 30, 2011

Regulatory And Environmental Developments Disclosure [Abstract]

Regulatory and Environmental Developments

Regulatory and Environmental Developments

Environmental Developments

Cross-State Air Pollution Rule

On July 6, 2011, the US EPA adopted the Cross-State Air Pollution Rule ("CSAPR"). CSAPR is the final form of a previously proposed replacement for the Clean Air Interstate Rule ("CAIR"), originally called the Clean Air Transport Rule that was released in 2010. CSAPR establishes emissions reductions for annual sulfur dioxide ("SO₂") emissions and annual and ozone season nitrogen oxide ("NOx") 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 NOx emissions from operations will need to be matched by a sufficient amount of SO₂ or NOx 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 NOx allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual or seasonal compliance period, units must surrender allowances for each ton of SO₂ and NOx emitted or face penalties. While trading of allowances is permitted within designated groups of states, the rule provides for penalties against a unit with emissions in excess of its predefined "assurance level," but only if the state in which it is located also exceeds its budgeted emissions level. On October 6, 2011, the US EPA announced a proposed revision to the rule that would effectively eliminate such penalties in the first phase.

EMG believes that Midwest Generation's current environmental remediation plan developed to comply with the CPS, along with the allowances allocated to it under CSAPR, will be sufficient to comply with the requirements of CSAPR and the US EPA's proposed regulation on hazardous air pollutant emissions. In order to achieve compliance, Midwest Generation has begun work to install SO₂ controls at certain of its plants.

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 Homer City will be able to acquire allowances for 2012 and 2013 in sufficient quantity to cover its normal operations and whether it will be able to pass through the cost of such allowances in the marketplace. Also, Homer City's SO₂ emissions could exceed its assurance level, and, therefore, unless the proposed revision to the rule is adopted, Homer City could be subject to penalties depending on whether, collectively, emissions from all of the subject electrical generating facilities in Pennsylvania exceed the state's budgeted emissions level. Accordingly, Homer City is evaluating alternative options, including reduced dispatch and fuel modifications, for complying with Phase I of CSAPR. The cost of allowances, together with possible operational impacts or reductions of output that 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, including some expenditures 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. An application for a construction permit to install the additional controls was filed on October 3, 2011 with the Pennsylvania Department of Environmental Protection.

Homer City does not currently have sufficient capital and does not expect to generate sufficient funds from operations to complete such retrofits and will have to seek third-party financing, which will be subject to decisions by Homer City's lessors, holders of bonds who provided financing for the sale-leaseback transaction 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.

In July 2011, EME asked the US EPA to stay the effectiveness of CSAPR pending judicial review, and in October 2011, Homer City asked the US EPA to reconsider the rule. In August 2011, Homer City asked the United States Court of Appeals for the District of Columbia to review CSAPR and requested a stay of the rule while its motion is pending. Numerous similar challenges have been filed by other industry participants and by several states.

Proposed Hazardous Air Pollutant Regulations

In March 2011, the US EPA 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 December 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.

Ozone and Particulates

In September 2011, President Obama announced that the proposed revision to the National Ambient Air Quality Standards ("NAAQS") for ozone, which was expected to have set a more stringent standard for primary ozone and a distinct secondary standard to protect sensitive vegetation and ecosystems, was being withdrawn. The ozone NAAQS established in 2008 remains in place, but the implementation process must be completed before the 0.075 parts-per-million standard can be enforced. The US EPA has indicated that it intends to issue initial area designations of attainment, nonattainment, and unclassifiable areas across the nation in 2012. States will then be required develop and submit state implementation plans outlining how compliance with the 2008 NAAQS will be achieved. New primary and secondary ozone standards are expected in 2014.

Water Quality

Once-Through Cooling Issues

In March 2011, the US EPA 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 California utilities to procure 33% of their electricity requirements from renewable resources, as defined in the statute. The impact of the new 33% law will depend on how the CPUC and CEC implement 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 case brought by the Alaskan Native Village of Kivalina against Edison International and other defendants, 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 stay of the appeal has now been lifted and argument before the Ninth Circuit is scheduled for November 2011. Kivalina is seeking damages of up to $400 million for the cost of relocating the village.

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. Edison International was dismissed as a defendant in this complaint in July 2011, but SCE and EME remain defendants.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2011

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 nine-month periods ended September 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 $1.1 billion at both September 30, 2011 and December 31, 2010. Generally, the carrying value of cash equivalents equals the fair value, as these 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 $215 million and $197 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at September 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)	September 30, 2011		December 31, 2010
Coal, gas, fuel oil and other raw materials	$	191	$	184
Spare parts, materials and supplies	401		384
Total inventory	$	592	$	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 September 30,					Nine months ended September 30,
(in millions)	2011		2010			2011		2010
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	426	$	514		$	805	$	1,086
Participating securities dividends	—		(3		)	—		(5		)
Income from continuing operations available to common shareholders	$	426	$	511		$	805	$	1,081
Weighted average common shares outstanding	326		326			326		326
Basic earnings per share – continuing operations	$	1.31	$	1.57		$	2.47	$	3.32
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	426	$	511		$	805	$	1,081
Income impact of assumed conversions	1		2			3		3
Income from continuing operations available to common shareholders and assumed conversions	$	427	$	513		$	808	$	1,084
Weighted average common shares outstanding	326		326			326		326
Incremental shares from assumed conversions	3		2			3		2
Adjusted weighted average shares – diluted	329		328			329		328
Diluted earnings per share – continuing operations	$	1.30	$	1.57		$	2.46	$	3.30

Stock-based compensation awards to purchase 5,943,378 and 9,700,218 shares of common stock for the three months ended September 30, 2011 and 2010, respectively, and 8,970,290 and 6,154,826 shares of common stock for the nine months ended September 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 Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2011

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory assets included on the consolidated balance sheets

(in millions)	September 30, 2011		December 31, 2010
Current:
Regulatory balancing accounts	$	191	$	213
Energy derivatives	262		162
Other	1		3
Total Current	454		378
Long-term:
Deferred income taxes – net	1,938		1,855
Pensions and other postretirement benefits	1,084		1,097
Unamortized generation investment – net	323		355
Unamortized loss on reacquired debt	253		268
Energy derivatives	214		177
Nuclear-related investment – net	160		154
Unamortized transmission and distribution investment – net	153		105
Regulatory balancing accounts	62		56
Other	299		280
Total Long-term	4,486		4,347
Total Regulatory Assets	$	4,940	$	4,725

Regulatory liabilities included on the consolidated balance sheets

(in millions)	September 30, 2011		December 31, 2010
Current:
Regulatory balancing accounts	$	728	$	733
Other	6		5
Total Current	734		738
Long-term:
Costs of removal	2,663		2,623
Asset Retirement Obligations	944		1,099
Regulatory balancing accounts	873		802
Other	1		—
Total Long-term	4,481		4,524
Total Regulatory Liabilities	$	5,215	$	5,262

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Income Taxes

9 Months Ended

Sep. 30, 2011

Income Tax Disclosure [Abstract]

Income Taxes

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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Income from continuing operations before income taxes	$	683		$	774		$	1,217		$	1,386
Provision for income tax at federal statutory rate of 35%	239			271			426			485
Increase (decrease) in income tax from:
Items presented with related state income tax, net:
Global Settlement related1	—			(37		)	—			(175		)
Change in tax accounting method for asset removal costs2	—			—			—			(40		)
State tax – net of federal benefit	30			34			43			57
Health care legislation3	—			—			—			39
Production and housing credits	(12		)	(14		)	(48		)	(48		)
Property-related and other	(15		)	(7		)	(52		)	(57		)
Total income tax expense from continuing operations	$	242		$	247		$	369		$	261
Effective tax rate	35		%	32		%	30		%	19		%

¹  During the nine months ended September 30, 2010, Edison International recognized a $175 million earnings benefit resulting from the Global Settlement, including $138 million in the second quarter resulting from the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service ("IRS") in 2009 and revision to interest recorded on the federal Global Settlement, and $37 million in the third quarter resulting from receipt of the final interest determination from the California Franchise Tax Board.

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 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	53			60
Tax positions taken during a prior year:
Increases	60			251
Decreases	(37		)	(86		)
Decreases for settlements during the period	—			(82		)
Balance at September 30,	$	641		$	807

As of September 30, 2011 and December 31, 2010, $500 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 $191 million, including interest and penalties through September 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 $92 million, including interest through September 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 $230 million and $213 million as of September 30, 2011 and December 31, 2010, respectively.

The net after-tax interest and penalties recognized in income tax expense was $5 million and $10 million for the three- and nine-month periods ended September 30, 2011, respectively, compared to a benefit of $7 million and $95 million for the same periods in 2010.

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Supplemental Cash Flows Information

9 Months Ended

Sep. 30, 2011

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flows Information

Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

	Nine months ended September 30,
(in millions)	2011			2010
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	529		$	486
Tax payments (refunds) – net	(330		)	44
Noncash investing and financing activities:
Accrued capital expenditures	$	393		$	421
Details of debt exchange:
Pollution-control bonds redeemed	$	(86	)	$	(303	)
Pollution-control bonds issued	86			303
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	12			9

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Compensation and Benefit Plans

9 Months Ended

Sep. 30, 2011

Compensation and Retirement Disclosure [Abstract]

Compensation and Benefit Plans

Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

During the nine months ended September 30, 2011, Edison International made contributions of $113 million and during the remainder of 2011, expects to make $30 million of additional contributions. In 2011, annual contributions made to most of SCE's pension plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.

Expense components are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Service cost	$	43		$	34		$	129		$	102
Interest cost	52			54			156			162
Expected return on plan assets	(60		)	(52		)	(180		)	(156		)
Amortization of prior service cost	2			2			6			6
Amortization of net loss	6			7			18			21
Expense under accounting standards	43			45			129			135
Regulatory adjustment – deferred	(6		)	(14		)	(18		)	(42		)
Total expense recognized	$	37		$	31		$	111		$	93

Postretirement Benefits Other Than Pensions

During the nine months ended September 30, 2011, Edison International made contributions of $18 million and during the remainder of 2011, expects to make $38 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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Service cost	$	11		$	8		$	33		$	24
Interest cost	33			31			99			93
Expected return on plan assets	(28		)	(25		)	(84		)	(75		)
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss	9			8			27			24
Total expense	$	16		$	13		$	48		$	39

Stock-Based Compensation

During 2011, Edison International granted 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	3,394,229		37.95
Expired	(113,348	)	48.52
Forfeited	(369,267	)	33.03
Exercised	(1,557,548	)	26.22
Outstanding at September 30, 2011	20,496,275		34.51		6.07
Vested and expected to vest at September 30, 2011	20,021,144		34.53		6.02	$	123
Exercisable at September 30, 2011	12,043,993		34.93		4.52	84

At September 30, 2011, there was $23 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	153,067		30.19		153,067
Forfeited1	(119,835	)	42.64		(119,835	)
Nonvested at September 30, 2011	448,260		27.96		448,260		23.26

¹ Includes performance shares that expired with zero value as performance targets were not met.

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 September 30, 2011, there was $5 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	251,890		37.95
Forfeited	(27,114	)	32.05
Paid Out	(133,958	)	47.60
Nonvested at September 30, 2011	735,614		$	32.15

At September 30, 2011, there was $10 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $2 million in 2011, $5 million in 2012 and $3 million in 2013.

Supplemental Data on Stock Based Compensation

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2011		2010		2011		2010
Stock based compensation expense1	$	8	$	9	$	25	$	26
Income tax benefits related to stock compensation expense	3		3		10		10
Excess tax benefits2	3		3		7		5
Stock options
Cash used to purchase shares to settle options	20		17		59		30
Cash from participants to exercise stock options	16		10		41		19
Value of options exercised	4		7		18		11
Restricted stock units
Value of shares settled	1		—		6		—
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.

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Compensation and Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2011

Compensation and Retirement Disclosure [Abstract]

Expense components for pension plan

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Service cost	$	43		$	34		$	129		$	102
Interest cost	52			54			156			162
Expected return on plan assets	(60		)	(52		)	(180		)	(156		)
Amortization of prior service cost	2			2			6			6
Amortization of net loss	6			7			18			21
Expense under accounting standards	43			45			129			135
Regulatory adjustment – deferred	(6		)	(14		)	(18		)	(42		)
Total expense recognized	$	37		$	31		$	111		$	93

Expense components for postretirement benefits other than pension

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Service cost	$	11		$	8		$	33		$	24
Interest cost	33			31			99			93
Expected return on plan assets	(28		)	(25		)	(84		)	(75		)
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss	9			8			27			24
Total expense	$	16		$	13		$	48		$	39

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	3,394,229		37.95
Expired	(113,348	)	48.52
Forfeited	(369,267	)	33.03
Exercised	(1,557,548	)	26.22
Outstanding at September 30, 2011	20,496,275		34.51		6.07
Vested and expected to vest at September 30, 2011	20,021,144		34.53		6.02	$	123
Exercisable at September 30, 2011	12,043,993		34.93		4.52	84

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	153,067		30.19		153,067
Forfeited1	(119,835	)	42.64		(119,835	)
Nonvested at September 30, 2011	448,260		27.96		448,260		23.26

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	251,890		37.95
Forfeited	(27,114	)	32.05
Paid Out	(133,958	)	47.60
Nonvested at September 30, 2011	735,614		$	32.15

Schedule of Supplemental Data on Stock Based Compensation

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2011		2010		2011		2010
Stock based compensation expense1	$	8	$	9	$	25	$	26
Income tax benefits related to stock compensation expense	3		3		10		10
Excess tax benefits2	3		3		7		5
Stock options
Cash used to purchase shares to settle options	20		17		59		30
Cash from participants to exercise stock options	16		10		41		19
Value of options exercised	4		7		18		11
Restricted stock units
Value of shares settled	1		—		6		—
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.

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Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

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	September 30, 2011	December 31, 2010
Electricity options, swaps and forwards	GWh	30,143	32,138
Natural gas options, swaps and forwards	Bcf	266	250
CRRs	GWh	146,628	181,291
Tolling arrangements	GWh	104,822	114,599

Fair Value of Derivative Instruments

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

	Derivative Assets									Derivative Liabilities1
(in millions)	Short- Term			Long- Term			Subtotal			Short- Term			Long- Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	82		$	145		$	227		$	305		$	577		$	882		$	655
Netting and collateral	(14		)	(13		)	(27		)	(18		)	(23		)	(41		)	(14		)
Total	$	68		$	132		$	200		$	287		$	554		$	841		$	641

¹  Includes the fair value of derivatives with SCE's consolidated affiliates; however, in Edison International’s consolidated financial statements, the fair value of such derivatives is eliminated.

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 that such gains or losses will be part of the purchased power costs recovered 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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Realized losses	$	(58	)	$	(53	)	$	(132	)	$	(116	)
Unrealized losses	(110		)	(165		)	(433		)	(1,022		)

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 $162 million and $67 million as of September 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 September 30, 2011, SCE would be required to post $23 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:

September 30, 2011
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges		Economic Hedges		Trading Activities
Electricity	Forwards/Futures	Sales	GWh	15,910	1	13,353	3	36,597
Electricity	Forwards/Futures	Purchases	GWh	101	1	13,230	3	42,429
Electricity	Capacity	Sales	MW-Day (in thousands)	134	2	—		12	2
Electricity	Capacity	Purchases	MW-Day (in thousands)	12	2	—		219	2
Electricity	Congestion	Sales	GWh	—		90	4	15,910	4
Electricity	Congestion	Purchases	GWh	—		4,023	4	253,688	4
Natural gas	Forwards/Futures	Sales	bcf	—		—		55.3
Natural gas	Forwards/Futures	Purchases	bcf	—		—		53.4
Fuel oil	Forwards/Futures	Sales	barrels	—		—		100,000
Fuel oil	Forwards/Futures	Purchases	barrels	—		240,000		140,000
Coal	Forwards/Futures	Sales	tons	—		—		1,485,000
Coal	Forwards/Futures	Purchases	tons	—		—		1,485,000

(in millions)
Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date
Accreting forward starting interest rate swap	Convert floating rate (1-month LIBOR debt to fixed rate (0.8135%) debt	Cash flow	$	39	May 2013
Accreting interest rate swap	Convert floating rate (1-month LIBOR debt to fixed rate (0.79%) debt	Cash flow	24		May 2013
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 forward starting interest rate swap	Convert floating rate (3-month LIBOR debt to fixed rate (3.5429%) debt	Cash flow	398		May 2023
Amortizing forward starting interest rate swap	Convert floating rate (3-month LIBOR debt to fixed rate (4.0025%) debt	Cash flow	48		May 2023
Amortizing interest rate swap	Convert floating rate (3-month LIBOR debt to fixed rate (4.29%) debt	Cash flow	119		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:

September 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	$	34		$	8		$	42		$	16		$	90		$	106		$	(64	)
Economic hedges	29			3			32			31			2			33			(1		)
Trading activities	132			102			234			96			37			133			101
	195			113			308			143			129			272			36
Netting and collateral received1	(163		)	(54		)	(217		)	(140		)	(49		)	(189		)	(28		)
Total	$	32		$	59		$	91		$	3		$	80		$	83		$	8

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 Nine Months Ended September 30,						Income Statement Location
(in millions)	2011			2010
Beginning of period derivative gains	$	27		$	175
Effective portion of changes in fair value	(62		)	102
Reclassification to net income	(29		)	(134		)	Competitive power generation revenue
End of period derivative gains (losses)	$	(64	)	$	143

¹  Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income (loss) at September 30, 2011 and 2010 were $(39) million and $86 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 of $4 million during each of the third quarters of 2011 and 2010, and $6 million and $5 million during the nine months ended September 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 September 30,					Nine months ended September 30,
(in millions)	Income Statement Location	2011			2010		2011		2010
Economic hedges	Competitive power generation revenue	$	(6	)	$	7	$	20	$	—
	Fuel	(3		)	2		1		—
Trading activities	Competitive power generation revenue	11			28		68		108

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. Future increases in power prices could expose EMG's subsidiaries to 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)	September 30, 2011		December 31, 2010
Collateral provided to counterparties:
Offset against derivative liabilities	$	16	$	8
Reflected in margin and collateral deposits	53		65
Collateral received from counterparties:
Offset against derivative assets	30		52

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Compensation and Benefit Plans (Details 2) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011 years	Sep. 30, 2010	Sep. 30, 2011 years	Sep. 30, 2010
Stock Options
Outstanding, at the beginning of period (in options)			19,142,209
Granted (in options)			3,394,229
Expired (in options)			(113,348)
Forfeited (in options)			(369,267)
Exercised (in options)			(1,557,548)
Outstanding, at the end of period (in options)	20,496,275		20,496,275
Vested and expected to vest, at the end of period (in options)	20,021,144		20,021,144
Exercisable, at the end of period (in options)	12,043,993		12,043,993
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)	$ 48.52		$ 48.52
Forfeited (in dollars per option)	$ 33.03		$ 33.03
Exercised (in dollars per option)	$ 26.22		$ 26.22
Outstanding, at the end of period (in dollars per option)	$ 34.51		$ 34.51
Vested and expected to vest, at the end of period (in dollars per option)	$ 34.53		$ 34.53
Exercisable, at the end of period (in dollars per option)	$ 34.93		$ 34.93
Weighted-Average Remaining Contractual Term (Years)
Outstanding, at the end of period (in years)	6.07		6.07
Vested and expected to vest, at the end of period (in years)			6.02
Exercisable, at the end of period (in years)			4.52
Aggregate Intrinsic Value
Vested and expected to vest, at the end of period	$ 123		$ 123
Exercisable, at the end of period	84		84
Supplemental Data on Stock Based Compensation
Stock Based Compensation Expense	8	9	25	26
Income tax benefits related to stock compensation expense	3	3	10	10
Excess tax benefits	3	3	7	5
Cash used to purchase shares to settle options	20	17	59	30
Cash from participants to exercise stock options	16	10	41	19
Value of options exercised	4	7	18	11
Value of shares settled	1	0	6	0
Tax benefits realized from settlement of awards	0	0	2	0
Performance Shares
Weighted-Average Fair Value
Total unrecognized compensation cost	5		5
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)			153,067
Forfeited (in shares)			(119,835)
Nonvested, at the end of the period (in shares)	448,260		448,260
Weighted-Average Fair Value
Nonvested, at the beginning of the period (in dollars per share)			$ 30.99
Granted (in dollars per share)			$ 30.19
Forfeited (in dollars per share)	$ 42.64		$ 42.64
Nonvested, at the end of the period (in dollars per share)	$ 27.96		$ 27.96
Performance shares classified as liability awards
Performance Shares
Nonvested, at the beginning of the period (in shares)			415,028
Granted (in shares)			153,067
Forfeited (in shares)			(119,835)
Nonvested, at the end of the period (in shares)	448,260		448,260
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)	$ 23.26		$ 23.26
Restricted Stock Units
Performance Shares
Nonvested, at the beginning of the period (in shares)			644,796
Granted (in shares)			251,890
Forfeited (in shares)			(27,114)
Paid out (in shares)			(133,958)
Nonvested, at the end of the period (in shares)	735,614		735,614
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)	$ 32.05		$ 32.05
Paid out (in dollars per share)			$ 47.60
Nonvested, at the end of the period (in dollars per share)	$ 32.15		$ 32.15
Total unrecognized compensation cost	10		10
Compensation cost to be recognized in 2011	2		2
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	$ 23		$ 23
Weighted-average period, recognition of unrecognized compensation cost (in years)			3

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data	Sep. 30, 2011	Dec. 31, 2010
Receivables, allowances for uncollectible accounts (in dollars)	$ 97	$ 85
Utility property, plant and equipment, accumulated depreciation (in dollars)	6,745	6,319
Competitive power generation and other property, plant and equipment, accumulated depreciation (in dollars)	$ 2,083	$ 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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Consolidated Statements of Changes in Equity

9 Months Ended

Sep. 30, 2011

Stockholders' Equity Note [Abstract]

Consolidated Statements of Changes in Equity

Consolidated Statements of Changes in Equity

The following table provides the changes in equity for the nine months ended September 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 (loss)	—			—			802			802			(1		)	44			845
Other comprehensive loss	—			(48		)	—			(48		)	—			—			(48		)
Common stock dividends declared ($0.96 per share)	—			—			(313		)	(313		)	—			—			(313		)
Dividends, distributions to noncontrolling interests and other	—			—			—			—			(1		)	(44		)	(45		)
Stock-based compensation and other	7			—			(21		)	(14		)	—			—			(14		)
Noncash stock-based compensation and other	22			—			(3		)	19			—			(1		)	18
Purchase of noncontrolling interests1	(14		)	—			—			(14		)	—			—			(14		)
Issuance of preference stock	—			—			—			—			—			123			123
Balance at September 30, 2011	$	2,346		$	(124	)	$	8,793		$	11,015		$	2		$	1,029		$	12,046

¹  During the nine months ended September 30, 2011, EMG purchased the remaining interests in Pinnacle Wind Force, LLC, and Broken Bow I, LLC and all assets of the Crofton Bluffs project. All three projects are now 100% owned by EMG. The purchases of the noncontrolling interests were accounted for as equity transactions between controlling and noncontrolling interest holders.

The following table provides the changes in equity for the nine months ended September 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	—		—			1,090			1,090			—			39			1,129
Other comprehensive loss	—		(11		)	—			(11		)	—			—			(11		)
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 ($0.945 per share)	—		—			(308		)	(308		)	—			—			(308		)
Dividends, distributions to noncontrolling interests and other	—		—			—			—			(4		)	(39		)	(43		)
Stock-based compensation and other	5		—			(12		)	(7		)	—			—			(7		)
Noncash stock-based compensation and other	16		—			(2		)	14			—			—			14
Balance at September 30, 2010	$	2,325	$	26		$	8,283		$	10,634		$	5		$	907		$	11,546

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Summary of Significant Accounting Policies (Details 2) (USD $) In Millions, except Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Basic earnings (loss) per share - continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$ 426	$ 514	$ 805	$ 1,086
Participating securities dividends	0	(3)	0	(5)
Income from continuing operations available to common shareholders	426	511	805	1,081
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)	$ 1.31	$ 1.57	$ 2.47	$ 3.32
Diluted earnings (loss) per share - continuing operations:
Income from continuing operations available to common shareholders	426	511	805	1,081
Income impact of assumed conversions	1	2	3	3
Income from continuing operations available to common shareholders and assumed conversions	$ 427	$ 513	$ 808	$ 1,084
Weighted average common shares 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	2,000,000	3,000,000	2,000,000
Adjusted weighted average shares - diluted (in shares)	329,000,000	328,000,000	329,000,000	328,000,000
Diluted earnings (loss) per share - continuing operations (in dollars per share)	$ 1.30	$ 1.57	$ 2.46	$ 3.30
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)	5,943,378	9,700,218	8,970,290	6,154,826

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2011

Income Tax Disclosure [Abstract]

Reconciliation of Income Tax Expense

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Income from continuing operations before income taxes	$	683		$	774		$	1,217		$	1,386
Provision for income tax at federal statutory rate of 35%	239			271			426			485
Increase (decrease) in income tax from:
Items presented with related state income tax, net:
Global Settlement related1	—			(37		)	—			(175		)
Change in tax accounting method for asset removal costs2	—			—			—			(40		)
State tax – net of federal benefit	30			34			43			57
Health care legislation3	—			—			—			39
Production and housing credits	(12		)	(14		)	(48		)	(48		)
Property-related and other	(15		)	(7		)	(52		)	(57		)
Total income tax expense from continuing operations	$	242		$	247		$	369		$	261
Effective tax rate	35		%	32		%	30		%	19		%

¹  During the nine months ended September 30, 2010, Edison International recognized a $175 million earnings benefit resulting from the Global Settlement, including $138 million in the second quarter resulting from the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service ("IRS") in 2009 and revision to interest recorded on the federal Global Settlement, and $37 million in the third quarter resulting from receipt of the final interest determination from the California Franchise Tax Board.

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	53			60
Tax positions taken during a prior year:
Increases	60			251
Decreases	(37		)	(86		)
Decreases for settlements during the period	—			(82		)
Balance at September 30,	$	641		$	807

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Preferred and Preference Stock of Utility (Details) (USD $)	1 Months Ended
	Mar. 31, 2011
Preferred And Preference Stock Of Utility Disclosure [Abstract]
Shares issued (in shares)	1,250,000
Preference stock (as a percent)	6.50%
Preference share, liquidation value (in dollars per share)	$ 100

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Other Investments (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	$ 2,297,000,000		$ 2,297,000,000		$ 2,185,000,000
Unrealized Holding Gains Net of Losses on Investments in Trust			1,100,000,000		1,300,000,000
Summary of changes in the fair value of the trust
Balance at beginning of period	3,657,000,000	3,083,000,000	3,480,000,000	3,140,000,000	3,140,000,000
Realized gains - net	41,000,000	14,000,000	76,000,000	48,000,000
Unrealized gains (losses) - net	(305,000,000)	233,000,000	(199,000,000)	90,000,000
Other-than-temporary impairments	(22,000,000)	(5,000,000)	(35,000,000)	(16,000,000)
Interest, dividends, contributions and other	22,000,000	22,000,000	71,000,000	85,000,000
Balance at end of period	3,393,000,000	3,347,000,000	3,393,000,000	3,347,000,000	3,480,000,000
Proceeds from sale of securities	962,000,000	302,000,000	2,108,000,000	903,000,000
Southern California Edison Company
Fair Value Disclosures:
Contributions received for decommissioning trusts			23,000,000
Period of reviewing contributions from decommissioning trusts (in years)			3
Stocks
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	861,000,000		861,000,000		895,000,000
Summary of changes in the fair value of the trust
Balance at end of period	1,721,000,000		1,721,000,000		2,029,000,000
Municipal bonds
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	644,000,000		644,000,000		706,000,000
Summary of changes in the fair value of the trust
Balance at end of period	767,000,000		767,000,000		790,000,000
U.S. government and agency securities
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	445,000,000		445,000,000		270,000,000
Summary of changes in the fair value of the trust
Balance at end of period	501,000,000		501,000,000		288,000,000
Corporate bonds
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	266,000,000		266,000,000		288,000,000
Summary of changes in the fair value of the trust
Balance at end of period	318,000,000		318,000,000		346,000,000
Short-term investments
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	81,000,000		81,000,000		26,000,000
Summary of changes in the fair value of the trust
Balance at end of period	$ 86,000,000		$ 86,000,000		$ 27,000,000

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Compensation and Benefit Plans (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Pension Plans
Pension and Other Postretirement Benefits
Additional plan year contributions	$ 30		$ 30
Employer contributions			113
Expense components are:
Service cost	43	34	129	102
Interest cost	52	54	156	162
Expected return on plan assets	(60)	(52)	(180)	(156)
Amortization of prior service cost (credit)	2	2	6	6
Amortization of net loss	6	7	18	21
Expense under accounting standards	43	45	129	135
Regulatory adjustment - deferred	(6)	(14)	(18)	(42)
Total expense recognized	37	31	111	93
Postretirement Benefits Other Than Pensions
Pension and Other Postretirement Benefits
Additional plan year contributions	38		38
Employer contributions			18
Expense components are:
Service cost	11	8	33	24
Interest cost	33	31	99	93
Expected return on plan assets	(28)	(25)	(84)	(75)
Amortization of prior service cost (credit)	(9)	(9)	(27)	(27)
Amortization of net loss	9	8	27	24
Total expense recognized	$ 16	$ 13	$ 48	$ 39

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Variable Interest Entities

9 Months Ended

Sep. 30, 2011

Variable Interest Entities Disclosure [Abstract]

Variable Interest Entities

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 September 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)	September 30, 2011		December 31, 2010
Current assets	$	40	$	26
Net property, plant and equipment	702		739
Other long-term assets	6		6
Total assets	$	748	$	771
Current liabilities	$	28	$	25
Long-term debt net of current portion	67		71
Deferred revenues	69		71
Other long-term liabilities	21		21
Total liabilities	$	185	$	188
Noncontrolling interests	$	2	$	4

At September 30, 2011 and December 31, 2010, assets serving as collateral for the debt obligations had a carrying value of $160 million and $163 million, respectively, and primarily consist of property, plant and equipment.

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has 16 power purchase agreements ("PPAs") that have variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to fuel 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 September 30, 2011 and the amounts that SCE paid to these projects were $178 million and $205 million for the three months ended September 30, 2011 and 2010, respectively, and $347 million and $447 million for the nine months ended September 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 September 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.

EMG accounts for its interest in three renewable wind generating facilities under the equity method. At December 31, 2010, EMG had interests in 2 renewable wind generating facilities, the Elkhorn Ridge and San Juan Mesa projects. In addition to these 2 projects, at September 30, 2011, EMG had interests in Community Wind North, which achieved commercial operation on May 28, 2011. 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:

	September 30, 2011
(in millions)	Investment		Maximum Exposure
Natural gas-fired projects	$	340	$	340
Renewable energy projects	228		228

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 September 30, 2011, entities which EMG has accounted for under the equity method had indebtedness of $64 million, of which $16 million is proportionate to EMG's ownership interest in this project.

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Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified					1 Months Ended			3 Months Ended		9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Variable Interest Entity, Primary Beneficiary	Dec. 31, 2010 Variable Interest Entity, Primary Beneficiary	Apr. 30, 2011 Variable Interest Entity, Primary Beneficiary EMG Wind Projects	Sep. 30, 2011 Variable Interest Entity, Primary Beneficiary EMG Wind Projects mW	Dec. 31, 2010 Variable Interest Entity, Primary Beneficiary EMG Wind Projects mW	Sep. 30, 2011 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts mW	Sep. 30, 2010 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts	Sep. 30, 2011 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts mW	Sep. 30, 2010 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts
Details of projects or entities
Number of projects						13	14	16		16
Number of Projects Consolidated						0	14
Power generating capacity for majority interest (in megawatts)						570	580	3,820		3,820
Sale of ownership interest (as a percent)					75.00%
Summarized balance sheet information of VIEs
Current assets	$ 4,751	$ 4,422	$ 40	$ 26
Net property, plant and equipment	5,579	5,406	702	739
Other long-term assets	619	644	6	6
Total assets	47,672	45,530	748	771
Current liabilities	4,161	3,952	28	25
Long-term debt net of current portion	13,010	12,371	67	71
Deferred revenues			69	71
Other long-term liabilities	2,454	2,041	21	21
Total liabilities	35,626	34,036	185	188
Noncontrolling interests	1,031	911	2	4
Assets serving as collateral for the debt obligations			160	163
Power Purchase Agreement With Tolling Agreement								6		6
Power Purchase Agreement With Qualified Facilities								10		10
Payments to unconsolidated VIEs, power purchase contracts								$ 178	$ 205	$ 347	$ 447

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Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2011

Variable Interest Entities Disclosure [Abstract]

Summarized financial information of the consolidated projects

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

(in millions)	September 30, 2011		December 31, 2010
Current assets	$	40	$	26
Net property, plant and equipment	702		739
Other long-term assets	6		6
Total assets	$	748	$	771
Current liabilities	$	28	$	25
Long-term debt net of current portion	67		71
Deferred revenues	69		71
Other long-term liabilities	21		21
Total liabilities	$	185	$	188
Noncontrolling interests	$	2	$	4

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

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

	September 30, 2011
(in millions)	Investment		Maximum Exposure
Natural gas-fired projects	$	340	$	340
Renewable energy projects	228		228

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Business Segments (Details)	9 Months Ended
	Sep. 30, 2011
Segment Reporting [Abstract]
Segment Reporting, Number of Segments	2

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Accumulated Other Comprehensive Loss (Tables)

9 Months Ended

Sep. 30, 2011

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

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	(55		)	7			—			(48		)
Balance at September 30, 2011	$	(39	)	$	(80	)	$	(5	)	$	(124	)

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Consolidated Statements of Changes in Equity (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			$ 11,494	$ 11,006
Net income (loss)	441	523	845	1,129
Other comprehensive (loss)	(27)	38	(48)	(11)
Deconsolidation of variable interest entities				(249)
Cumulative effect of a change in accounting principle, net of tax		15		15
Common stock dividends declared ($0.96 and $0.945 per share for the period ended September 30, 2011 and September 30, 2010 respectively)			(313)	(308)
Dividends, distributions to noncontrolling interests and other			(45)	(43)
Stock-based compensation and other			(14)	(7)
Noncash stock-based compensation and other			18	14
Purchase of noncontrolling interests			(14)
Issuance of preference stock			123
Balance, at the end of period	12,046	11,546	12,046	11,546
Common stock dividends declared (in dollars per share)	$ 0.320	$ 0.315	$ 0.960	$ 0.945
Competitive Power Generation [Member]
Noncontrolling Interest, Ownership Percentage by Parent	100.00%		100.00%
Equity Attributable to Edison International
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			10,583	9,841
Net income (loss)			802	1,090
Other comprehensive (loss)			(48)	(11)
Deconsolidation of variable interest entities				0
Cumulative effect of a change in accounting principle, net of tax		15		15
Common stock dividends declared ($0.96 and $0.945 per share for the period ended September 30, 2011 and September 30, 2010 respectively)			(313)	(308)
Dividends, distributions to noncontrolling interests and other			0	0
Stock-based compensation and other			(14)	(7)
Noncash stock-based compensation and other			19	14
Purchase of noncontrolling interests			(14)
Issuance of preference stock			0
Balance, at the end of period	11,015	10,634	11,015	10,634
Common Stock
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			2,331	2,304
Net income (loss)			0	0
Other comprehensive (loss)			0	0
Deconsolidation of variable interest entities				0
Cumulative effect of a change in accounting principle, net of tax		0		0
Common stock dividends declared ($0.96 and $0.945 per share for the period ended September 30, 2011 and September 30, 2010 respectively)			0	0
Dividends, distributions to noncontrolling interests and other			0	0
Stock-based compensation and other			7	5
Noncash stock-based compensation and other			22	16
Purchase of noncontrolling interests			(14)
Issuance of preference stock			0
Balance, at the end of period	2,346	2,325	2,346	2,325
Accumulated Other Comprehensive Loss
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			(76)	37
Net income (loss)			0	0
Other comprehensive (loss)			(48)	(11)
Deconsolidation of variable interest entities				0
Cumulative effect of a change in accounting principle, net of tax		0		0
Common stock dividends declared ($0.96 and $0.945 per share for the period ended September 30, 2011 and September 30, 2010 respectively)			0	0
Dividends, distributions to noncontrolling interests and other			0	0
Stock-based compensation and other			0	0
Noncash stock-based compensation and other			0	0
Purchase of noncontrolling interests			0
Issuance of preference stock			0
Balance, at the end of period	(124)	26	(124)	26
Retained Earnings
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			8,328	7,500
Net income (loss)			802	1,090
Other comprehensive (loss)			0	0
Deconsolidation of variable interest entities				0
Cumulative effect of a change in accounting principle, net of tax		15		15
Common stock dividends declared ($0.96 and $0.945 per share for the period ended September 30, 2011 and September 30, 2010 respectively)			(313)	(308)
Dividends, distributions to noncontrolling interests and other			0	0
Stock-based compensation and other			(21)	(12)
Noncash stock-based compensation and other			(3)	(2)
Purchase of noncontrolling interests			0
Issuance of preference stock			0
Balance, at the end of period	8,793	8,283	8,793	8,283
Other
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			4	258
Net income (loss)			(1)	0
Other comprehensive (loss)			0	0
Deconsolidation of variable interest entities				(249)
Cumulative effect of a change in accounting principle, net of tax		0		0
Common stock dividends declared ($0.96 and $0.945 per share for the period ended September 30, 2011 and September 30, 2010 respectively)			0	0
Dividends, distributions to noncontrolling interests and other			(1)	(4)
Stock-based compensation and other			0	0
Noncash stock-based compensation and other			0	0
Purchase of noncontrolling interests			0
Issuance of preference stock			0
Balance, at the end of period	2	5	2	5
Preferred and Preference Stock
Increase (Decrease) in Stockholders' Equity
Balance, at the beginning of period			907	907
Net income (loss)			44	39
Other comprehensive (loss)			0	0
Deconsolidation of variable interest entities				0
Cumulative effect of a change in accounting principle, net of tax		0		0
Common stock dividends declared ($0.96 and $0.945 per share for the period ended September 30, 2011 and September 30, 2010 respectively)			0	0
Dividends, distributions to noncontrolling interests and other			(44)	(39)
Stock-based compensation and other			0	0
Noncash stock-based compensation and other			(1)	0
Purchase of noncontrolling interests			0
Issuance of preference stock			123
Balance, at the end of period	$ 1,029	$ 907	$ 1,029	$ 907

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Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Notional Volumes of Derivative Instruments for Electric Utility Segment

		Economic Hedges
Commodity	Unit of Measure	September 30, 2011	December 31, 2010
Electricity options, swaps and forwards	GWh	30,143	32,138
Natural gas options, swaps and forwards	Bcf	266	250
CRRs	GWh	146,628	181,291
Tolling arrangements	GWh	104,822	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 September 30, 2011:

	Derivative Assets									Derivative Liabilities1
(in millions)	Short- Term			Long- Term			Subtotal			Short- Term			Long- Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	82		$	145		$	227		$	305		$	577		$	882		$	655
Netting and collateral	(14		)	(13		)	(27		)	(18		)	(23		)	(41		)	(14		)
Total	$	68		$	132		$	200		$	287		$	554		$	841		$	641

¹  Includes the fair value of derivatives with SCE's consolidated affiliates; however, in Edison International’s consolidated financial statements, the fair value of such derivatives is eliminated.

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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Realized losses	$	(58	)	$	(53	)	$	(132	)	$	(116	)
Unrealized losses	(110		)	(165		)	(433		)	(1,022		)

Notional Volumes of Derivative Instruments for Competitive Power Generation Segment

September 30, 2011
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges		Economic Hedges		Trading Activities
Electricity	Forwards/Futures	Sales	GWh	15,910	1	13,353	3	36,597
Electricity	Forwards/Futures	Purchases	GWh	101	1	13,230	3	42,429
Electricity	Capacity	Sales	MW-Day (in thousands)	134	2	—		12	2
Electricity	Capacity	Purchases	MW-Day (in thousands)	12	2	—		219	2
Electricity	Congestion	Sales	GWh	—		90	4	15,910	4
Electricity	Congestion	Purchases	GWh	—		4,023	4	253,688	4
Natural gas	Forwards/Futures	Sales	bcf	—		—		55.3
Natural gas	Forwards/Futures	Purchases	bcf	—		—		53.4
Fuel oil	Forwards/Futures	Sales	barrels	—		—		100,000
Fuel oil	Forwards/Futures	Purchases	barrels	—		240,000		140,000
Coal	Forwards/Futures	Sales	tons	—		—		1,485,000
Coal	Forwards/Futures	Purchases	tons	—		—		1,485,000

(in millions)
Instrument	Purpose	Type of Hedge	Notional Amount		Expiration Date
Accreting forward starting interest rate swap	Convert floating rate (1-month LIBOR debt to fixed rate (0.8135%) debt	Cash flow	$	39	May 2013
Accreting interest rate swap	Convert floating rate (1-month LIBOR debt to fixed rate (0.79%) debt	Cash flow	24		May 2013
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 forward starting interest rate swap	Convert floating rate (3-month LIBOR debt to fixed rate (3.5429%) debt	Cash flow	398		May 2023
Amortizing forward starting interest rate swap	Convert floating rate (3-month LIBOR debt to fixed rate (4.0025%) debt	Cash flow	48		May 2023
Amortizing interest rate swap	Convert floating rate (3-month LIBOR debt to fixed rate (4.29%) debt	Cash flow	119		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

September 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	$	34		$	8		$	42		$	16		$	90		$	106		$	(64	)
Economic hedges	29			3			32			31			2			33			(1		)
Trading activities	132			102			234			96			37			133			101
	195			113			308			143			129			272			36
Netting and collateral received1	(163		)	(54		)	(217		)	(140		)	(49		)	(189		)	(28		)
Total	$	32		$	59		$	91		$	3		$	80		$	83		$	8

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 Nine Months Ended September 30,						Income Statement Location
(in millions)	2011			2010
Beginning of period derivative gains	$	27		$	175
Effective portion of changes in fair value	(62		)	102
Reclassification to net income	(29		)	(134		)	Competitive power generation revenue
End of period derivative gains (losses)	$	(64	)	$	143

¹  Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income (loss) at September 30, 2011 and 2010 were $(39) million and $86 million, respectively.

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

		Three months ended September 30,					Nine months ended September 30,
(in millions)	Income Statement Location	2011			2010		2011		2010
Economic hedges	Competitive power generation revenue	$	(6	)	$	7	$	20	$	—
	Fuel	(3		)	2		1		—
Trading activities	Competitive power generation revenue	11			28		68		108

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

(in millions)	September 30, 2011		December 31, 2010
Collateral provided to counterparties:
Offset against derivative liabilities	$	16	$	8
Reflected in margin and collateral deposits	53		65
Collateral received from counterparties:
Offset against derivative assets	30		52

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Accumulated Other Comprehensive Loss

9 Months Ended

Sep. 30, 2011

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

Accumulated Other Comprehensive Loss

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	(55		)	7			—			(48		)
Balance at September 30, 2011	$	(39	)	$	(80	)	$	(5	)	$	(124	)

Included in accumulated other comprehensive loss at September 30, 2011 was $10 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $49 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 $11 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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Accumulated Other Comprehensive (Loss) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended						9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Unrealized Gain (Loss) on Cash Flow Hedges	Sep. 30, 2011 Pension and PBOP- Net Gain (Loss)	Sep. 30, 2011 Pension and PBOP- Prior Service Cost	Dec. 31, 2010 Pension and PBOP- Prior Service Cost	Sep. 30, 2011 Commodity contracts	Sep. 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	(27)	38	(48)	(11)	(55)	7
Balance, at the end of period	(124)		(124)		(39)	(80)	(5)	(5)
Unrealized derivative gains (losses) after taxes recorded in accumulated other comprehensive income									10	(49)
Unrealized gains on cash flow hedges, net of tax, expected to be reclassified into earnings during the next 12 months									$ 11
Cash Flow Hedge Gain (Loss) Reclassification Period			12 months

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Other Income and Expenses (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Other income:
Equity Available Funds Used During Construction	$ 18	$ 24	$ 74	$ 76
Increase in cash surrender value of life insurance policies	6	7	19	19
Other	2	2	10	8
Total utility other income	26	33	103	103
Competitive power generation and other income	1	0	7	0
Total other income	27	33	110	103
Other expenses:
Civic, political and related activities and donations	6	7	21	21
Other	4	3	14	18
Total utility other expenses	10	10	35	39
Competitive power generation and other expenses	1	2	2	0
Total other expenses	$ 11	$ 12	$ 37	$ 39

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Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Disclosures [Abstract]

Fair Value Measurements

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 determine 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 September 30, 2011
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	1,056	$	—	$	—		$	—		$	1,056
Derivative contracts:
Electricity	—		43		213			(36		)	220
Natural gas	2		61		10			(6		)	67
Fuel oil	2		—		—			(2		)	—
Tolling	—		—		4			—			4
Coal	—		1		—			(1		)	—
Subtotal of commodity contracts	4		105		227			(45		)	291
Long-term disability plan	9		—		—			—			9
Nuclear decommissioning trusts:
Stocks3	1,721		—		—			—			1,721
Municipal bonds	—		767		—			—			767
U.S. government and agency securities	378		123		—			—			501
Corporate bonds4	—		318		—			—			318
Short-term investments, primarily cash equivalents5	2		151		—			—			153
Subtotal of nuclear decommissioning trusts	2,101		1,359		—			—			3,460
Total assets6	3,170		1,464		227			(45		)	4,816
Liabilities at Fair Value
Derivative contracts:
Electricity	—		17		84			(18		)	83
Natural gas	—		240		12			(12		)	240
Fuel oil	1		—		—			(1		)	—
Tolling	—		—		231			—			231
Subtotal of commodity contracts	1		257		327			(31		)	554
Interest rate contracts	—		80		—			—			80
Total liabilities	1		337		327			(31		)	634
Net assets (liabilities)	$	3,169	$	1,127	$	(100	)	$	(14	)	$	4,182

	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 69% and 67% of the equity investments were located in the United States at September 30, 2011 and December 31, 2010, respectively.

⁴  At September 30, 2011 and December 31, 2010, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $21 million and $27 million, respectively.

⁵  Excludes net liabilities of $67 million and $5 million at September 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 September 30, 2011 and December 31, 2010, 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 September 30,							Nine months ended September 30,
(in millions)	2011				2010			2011				2010
Fair value, net asset (liabilities) at beginning of period	$	(275	)		$	(703	)	$	97			$	62
Total realized/unrealized gains (losses):
Included in earnings1	(4		)		24			14				51
Included in regulatory assets and liabilities2	162			3	(142		)	(220		)	3	(924		)
Included in accumulated other comprehensive income	1				1			(2		)		5
Purchases	24				15			51				48
Settlements	(8		)		(76		)	(38		)		(128		)
Transfers in or out of Level 3	—				(12		)	(2		)		(7		)
Fair value, net liability at end of period	$	(100	)		$	(893	)	$	(100	)		$	(893	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period4	$	(110	)		$	(163	)	$	(425	)		$	(882	)

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  Includes the elimination of the fair value of derivatives with SCE's consolidated affiliates.

⁴  Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income was a loss of $3 million for the three months ended September 30, 2010, and gains of $7 million and $1 million for the nine months ended September 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 September 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 value and fair value of long-term debt are:

	September 30, 2011				December 31, 2010
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current portion	$	13,061	$	13,500	$	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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Regulatory Assets and Liabilities

9 Months Ended

Sep. 30, 2011

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)	September 30, 2011		December 31, 2010
Current:
Regulatory balancing accounts	$	191	$	213
Energy derivatives	262		162
Other	1		3
Total Current	454		378
Long-term:
Deferred income taxes – net	1,938		1,855
Pensions and other postretirement benefits	1,084		1,097
Unamortized generation investment – net	323		355
Unamortized loss on reacquired debt	253		268
Energy derivatives	214		177
Nuclear-related investment – net	160		154
Unamortized transmission and distribution investment – net	153		105
Regulatory balancing accounts	62		56
Other	299		280
Total Long-term	4,486		4,347
Total Regulatory Assets	$	4,940	$	4,725

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	September 30, 2011		December 31, 2010
Current:
Regulatory balancing accounts	$	728	$	733
Other	6		5
Total Current	734		738
Long-term:
Costs of removal	2,663		2,623
Asset Retirement Obligations	944		1,099
Regulatory balancing accounts	873		802
Other	1		—
Total Long-term	4,481		4,524
Total Regulatory Liabilities	$	5,215	$	5,262

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Business Segments (Details 2) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Reportable Segments Information
Operating Revenue:	$ 3,981	$ 3,788	$ 9,746	$ 9,340
Net Income (Loss) attributable to Edison International:	426	510	802	1,090
Total Assets:	47,672		47,672		45,530
Income (loss) from discontinued operations, net of tax	0	(4)	(3)	4
Electric Utility
Reportable Segments Information
Operating Revenue:	3,386	3,098	8,063	7,504
Net Income (Loss) attributable to Edison International:	406	394	838	858
Total Assets:	38,122		38,122		35,906
Competitive power generation
Reportable Segments Information
Operating Revenue:	596	691	1,686	1,838
Net Income (Loss) attributable to Edison International:	33	110	(17)	214
Total Assets:	9,881		9,881		9,597
Parent and other
Reportable Segments Information
Operating Revenue:	(1)	(1)	(3)	(2)
Net Income (Loss) attributable to Edison International:	(13)	6	(19)	18
Total Assets:	$ (331)		$ (331)		$ 27

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Summary of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Summary of Significant Accounting Policies [Line Items]
Segment Reporting, Number of Segments	2
Cash Equivalents
Money market funds	$ 1,100	$ 1,100
Maximum maturity period of cash equivalent investments (in months)	3
Cash reclassified to accounts payable under cash management program	215	197
Inventory
Coal, gas, fuel oil and other raw materials	191	184
Spare parts, materials and supplies	401	384
Total inventory	$ 592	$ 568
Electric Utility [Member]
Summary of Significant Accounting Policies [Line Items]
Supply of Electricity Area Covered	50,000

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value Disclosures [Abstract]

Fair value by level

	As of September 30, 2011
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	1,056	$	—	$	—		$	—		$	1,056
Derivative contracts:
Electricity	—		43		213			(36		)	220
Natural gas	2		61		10			(6		)	67
Fuel oil	2		—		—			(2		)	—
Tolling	—		—		4			—			4
Coal	—		1		—			(1		)	—
Subtotal of commodity contracts	4		105		227			(45		)	291
Long-term disability plan	9		—		—			—			9
Nuclear decommissioning trusts:
Stocks3	1,721		—		—			—			1,721
Municipal bonds	—		767		—			—			767
U.S. government and agency securities	378		123		—			—			501
Corporate bonds4	—		318		—			—			318
Short-term investments, primarily cash equivalents5	2		151		—			—			153
Subtotal of nuclear decommissioning trusts	2,101		1,359		—			—			3,460
Total assets6	3,170		1,464		227			(45		)	4,816
Liabilities at Fair Value
Derivative contracts:
Electricity	—		17		84			(18		)	83
Natural gas	—		240		12			(12		)	240
Fuel oil	1		—		—			(1		)	—
Tolling	—		—		231			—			231
Subtotal of commodity contracts	1		257		327			(31		)	554
Interest rate contracts	—		80		—			—			80
Total liabilities	1		337		327			(31		)	634
Net assets (liabilities)	$	3,169	$	1,127	$	(100	)	$	(14	)	$	4,182

	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 69% and 67% of the equity investments were located in the United States at September 30, 2011 and December 31, 2010, respectively.

⁴  At September 30, 2011 and December 31, 2010, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $21 million and $27 million, respectively.

⁵  Excludes net liabilities of $67 million and $5 million at September 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 September 30, 2011 and December 31, 2010, of cash surrender value of life insurance investments for deferred compensation.

Summary of changes in fair value of Level 3 assets and liabilities

	Three months ended September 30,							Nine months ended September 30,
(in millions)	2011				2010			2011				2010
Fair value, net asset (liabilities) at beginning of period	$	(275	)		$	(703	)	$	97			$	62
Total realized/unrealized gains (losses):
Included in earnings1	(4		)		24			14				51
Included in regulatory assets and liabilities2	162			3	(142		)	(220		)	3	(924		)
Included in accumulated other comprehensive income	1				1			(2		)		5
Purchases	24				15			51				48
Settlements	(8		)		(76		)	(38		)		(128		)
Transfers in or out of Level 3	—				(12		)	(2		)		(7		)
Fair value, net liability at end of period	$	(100	)		$	(893	)	$	(100	)		$	(893	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period4	$	(110	)		$	(163	)	$	(425	)		$	(882	)

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  Includes the elimination of the fair value of derivatives with SCE's consolidated affiliates.

⁴  Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income was a loss of $3 million for the three months ended September 30, 2010, and gains of $7 million and $1 million for the nine months ended September 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, including current portion

	September 30, 2011				December 31, 2010
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current portion	$	13,061	$	13,500	$	12,419	$	12,360

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Consolidated Balance Sheets (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
ASSETS
Cash and cash equivalents	$ 1,384	$ 1,389
Receivables, less allowances of $97 and $85 for uncollectible accounts at respective dates	1,218	931
Accrued unbilled revenue	709	442
Inventory	592	568
Prepaid taxes	72	390
Derivative assets	100	133
Restricted cash	15	2
Margin and collateral deposits	54	65
Regulatory assets	454	378
Other current assets	153	124
Total current assets	4,751	4,422
Nuclear decommissioning trusts	3,393	3,480
Investments in unconsolidated affiliates	569	559
Other investments	231	223
Total investments	4,193	4,262
Utility property, plant and equipment, less accumulated depreciation of $6,745 and $6,319 at respective dates	26,490	24,778
Competitive power generation and other property, plant and equipment, less accumulated depreciation of $2,083 and $1,865 at respective dates	5,579	5,406
Total property, plant and equipment	32,069	30,184
Derivative assets	191	437
Restricted deposits	43	47
Rent payments in excess of levelized rent expense under plant operating leases	1,320	1,187
Regulatory assets	4,486	4,347
Other long-term assets	619	644
Total long-term assets	6,659	6,662
Total assets	47,672	45,530
LIABILITIES AND EQUITY
Short-term debt	560	115
Current portion of long-term debt	51	48
Accounts payable	1,224	1,362
Accrued taxes	128	52
Accrued interest	207	205
Customer deposits	203	217
Derivative liabilities	290	217
Regulatory liabilities	734	738
Other current liabilities	764	998
Total current liabilities	4,161	3,952
Long-term debt	13,010	12,371
Deferred income taxes	6,003	5,625
Deferred investment tax credits	89	122
Customer advances	133	112
Derivative liabilities	344	468
Pensions and benefits	2,293	2,260
Asset retirement obligations	2,658	2,561
Regulatory liabilities	4,481	4,524
Other deferred credits and other long-term liabilities	2,454	2,041
Total deferred credits and other liabilities	18,455	17,713
Total liabilities	35,626	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)	2,346	2,331
Accumulated other comprehensive loss	(124)	(76)
Retained earnings	8,793	8,328
Total Edison International's common shareholders' equity	11,015	10,583
Preferred and preference stock of utility	1,029	907
Other noncontrolling interests	2	4
Total noncontrolling interests	1,031	911
Total equity	12,046	11,494
Total liabilities and equity	$ 47,672	$ 45,530

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Other Investments

9 Months Ended

Sep. 30, 2011

Regulated Entity, Other Assets, Noncurrent [Abstract]

Other Investments

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	September 30, 2011		December 31, 2010		September 30, 2011		December 31, 2010
Stocks	—	$	861	$	895	$	1,721	$	2,029
Municipal bonds	2051	644		706		767		790
U.S. government and agency securities	2041	445		270		501		288
Corporate bonds	2054	266		288		318		346
Short-term investments and receivables/payables	One-year	81		26		86		27
Total		$	2,297	$	2,185	$	3,393	$	3,480

Trust fund earnings (based on specific identification) increase the trust fund balance and the asset retirement obligations ("ARO") regulatory liability. Proceeds from sales of securities (which are reinvested) were $962 million and $302 million for the three months ended September 30, 2011 and 2010, respectively, and $2.1 billion and $903 million for the nine months ended September 30, 2011 and 2010, respectively. Unrealized holding gains, net of losses, were $1.1 billion and $1.3 billion at September 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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Balance at beginning of period	$	3,657		$	3,083		$	3,480		$	3,140
Realized gains – net	41			14			76			48
Unrealized gains (losses) – net	(305		)	233			(199		)	90
Other-than-temporary impairments	(22		)	(5		)	(35		)	(16		)
Interest, dividends, contributions and other	22			22			71			85
Balance at end of period	$	3,393		$	3,347		$	3,393		$	3,347

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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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended		12 Months Ended																																						3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2009	Sep. 30, 2011 Level 1	Dec. 31, 2010 Level 1	Sep. 30, 2011 Level 1 Stocks	Dec. 31, 2010 Level 1 Stocks	Sep. 30, 2011 Level 1 U.S. government and agency securities	Dec. 31, 2010 Level 1 U.S. government and agency securities	Sep. 30, 2011 Level 1 Short-term investments, primarily cash equivalents	Dec. 31, 2010 Level 1 Short-term investments, primarily cash equivalents	Sep. 30, 2011 Level 1 Commodity contracts.	Dec. 31, 2010 Level 1 Commodity contracts.	Sep. 30, 2011 Level 1 Natural gas	Dec. 31, 2010 Level 1 Natural gas	Sep. 30, 2011 Level 1 Fuel oil	Dec. 31, 2010 Level 1 Fuel oil	Sep. 30, 2011 Level 2	Dec. 31, 2010 Level 2	Sep. 30, 2011 Level 2 Municipal bonds	Dec. 31, 2010 Level 2 Municipal bonds	Sep. 30, 2011 Level 2 U.S. government and agency securities	Dec. 31, 2010 Level 2 U.S. government and agency securities	Sep. 30, 2011 Level 2 Corporate bonds	Dec. 31, 2010 Level 2 Corporate bonds	Sep. 30, 2011 Level 2 Short-term investments, primarily cash equivalents	Dec. 31, 2010 Level 2 Short-term investments, primarily cash equivalents	Sep. 30, 2011 Level 2 Commodity contracts.	Dec. 31, 2010 Level 2 Commodity contracts.	Sep. 30, 2011 Level 2 Electricity	Dec. 31, 2010 Level 2 Electricity	Sep. 30, 2011 Level 2 Natural gas	Dec. 31, 2010 Level 2 Natural gas	Sep. 30, 2011 Level 2 Coal	Dec. 31, 2010 Level 2 Coal	Sep. 30, 2011 Level 2 Interest rate contracts.	Dec. 31, 2010 Level 2 Interest rate contracts.	Sep. 30, 2011 Level 3	Sep. 30, 2010 Level 3	Sep. 30, 2011 Level 3	Sep. 30, 2010 Level 3	Dec. 31, 2010 Level 3	Sep. 30, 2011 Level 3 Commodity contracts.	Dec. 31, 2010 Level 3 Commodity contracts.	Sep. 30, 2011 Level 3 Electricity	Dec. 31, 2010 Level 3 Electricity	Sep. 30, 2011 Level 3 Natural gas	Dec. 31, 2010 Level 3 Natural gas	Sep. 30, 2011 Level 3 Tolling	Dec. 31, 2010 Level 3 Tolling	Sep. 30, 2011 Netting and Collateral	Dec. 31, 2010 Netting and Collateral	Sep. 30, 2011 Netting and Collateral Commodity contracts.	Dec. 31, 2010 Netting and Collateral Commodity contracts.	Sep. 30, 2011 Netting and Collateral Electricity	Dec. 31, 2010 Netting and Collateral Electricity	Sep. 30, 2011 Netting and Collateral Natural gas	Dec. 31, 2010 Netting and Collateral Natural gas	Sep. 30, 2011 Netting and Collateral Fuel oil	Dec. 31, 2010 Netting and Collateral Fuel oil	Sep. 30, 2011 Netting and Collateral Coal	Dec. 31, 2010 Netting and Collateral Coal	Sep. 30, 2011 Total	Dec. 31, 2010 Total	Sep. 30, 2011 Total Stocks	Dec. 31, 2010 Total Stocks	Sep. 30, 2011 Total Municipal bonds	Dec. 31, 2010 Total Municipal bonds	Sep. 30, 2011 Total U.S. government and agency securities	Dec. 31, 2010 Total U.S. government and agency securities	Sep. 30, 2011 Total Corporate bonds	Dec. 31, 2010 Total Corporate bonds	Sep. 30, 2011 Total Short-term investments, primarily cash equivalents	Dec. 31, 2010 Total Short-term investments, primarily cash equivalents	Sep. 30, 2011 Total Commodity contracts.	Dec. 31, 2010 Total Commodity contracts.	Sep. 30, 2011 Total Electricity	Dec. 31, 2010 Total Electricity	Sep. 30, 2011 Total Natural gas	Dec. 31, 2010 Total Natural gas	Sep. 30, 2011 Total Tolling	Dec. 31, 2010 Total Tolling	Sep. 30, 2011 Total Interest rate contracts.	Dec. 31, 2010 Total Interest rate contracts.	Sep. 30, 2011 Stocks	Dec. 31, 2010 Stocks	Sep. 30, 2011 Municipal bonds	Dec. 31, 2010 Municipal bonds	Sep. 30, 2011 U.S. government and agency securities	Dec. 31, 2010 U.S. government and agency securities	Sep. 30, 2011 Corporate bonds	Dec. 31, 2010 Corporate bonds
Assets at Fair Value
Money market funds		$ 1,100		$ 1,100				$ 1,056	$ 1,100																																																										$ 1,056	$ 1,100
Derivative contracts																4	9	2	1	2	8											105	139	43	70	61	69	1									227	492	213	363	10	11	4	118			(45)	(70)	(36)	(61)	(6)	(1)	(2)	(8)	(1)														291	570	220	372	67	80	4	118
Long-term disability plan								9	9																																																										9	9
Nuclear decommissioning trusts	3,347	3,393	3,347	3,480	3,657	3,083	3,140	2,101	2,245	1,721	2,029	378	215	2	1							1,359	1,240	767	790	123	73	318	346	151	31																																				3,460	3,485	1,721	2,029	767	790	501	288	318	346	153	32											1,721	2,029	767	790	501	288	318	346
Total assets								3,170	3,363													1,464	1,379																			227		227		492									(45)	(70)											4,816	5,164
Liabilities at Fair Value
Derivative Financial Instruments, Liabilities, Fair Value Disclosure																1				1												257	300	17	13	240	286		1	80	16						327	395	84	40	12	11	231	344			(31)	(26)	(18)	(21)	(12)	(4)	(1)			(1)													554	669	83	32	240	293	231	344	80	16
Total liabilities								1														337	316																			327		327		395									(31)	(26)											634	685
Net assets (liabilities)								3,169	3,363													1,127	1,063																			(100)		(100)		97									(14)	(44)											4,182	4,479
Percentage of equity investments located in the United States (as a percent)		69.00%		67.00%
Collateralized mortgage obligations and other asset backed securities		21		27
Receivables (payables) net related to investments		67		5
Cash surrender value of life insurance		31
Fair Value Disclosures Level 3
Fair value, net asset (liabilities) at beginning of period																																										(275)	(703)	97	62
Total realized/unrealized gains (losses):
Included in earnings																																										(4)	24	14	51
Included in regulatory assets and liabilities																																										162	(142)	(220)	(924)
Included in accumulated other comprehensive income																																										1	1	(2)	5
Purchases																																										24	15	51	48
Settlements																																										(8)	(76)	(38)	(128)
Transfers in or out of Level 3																																										0	(12)	(2)	(7)
Fair value, net liability at end of period																																										(100)	(893)	(100)	(893)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period																																										(110)	(163)	(425)	(882)
Unrealized gain loss related to Level 3 financial instruments reported within competitive power generation revenue	$ (3)	$ 7	$ 1

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Business Segments

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Business Segments

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 September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Operating Revenue:
Electric utility	$	3,386		$	3,098		$	8,063		$	7,504
Competitive power generation	596			691			1,686			1,838
Parent and other2	(1		)	(1		)	(3		)	(2		)
Consolidated Edison International	$	3,981		$	3,788		$	9,746		$	9,340
Net Income (Loss) attributable to Edison International:
Electric utility	$	406		$	394		$	838		$	858
Competitive power generation1	33			110			(17		)	214
Parent and other2	(13		)	6			(19		)	18
Consolidated Edison International	$	426		$	510		$	802		$	1,090

Segment balance sheet information was:

(in millions)	September 30, 2011			December 31, 2010
Total Assets:
Electric utility	$	38,122		$	35,906
Competitive power generation	9,881			9,597
Parent and other2	(331		)	27
Consolidated Edison International	$	47,672		$	45,530

¹ Includes earnings (losses) from discontinued operations of none and $(4) million for the three months ended September 30, 2011 and 2010, respectively, and $(3) million and $4 million for the nine months ended September 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 Cash Flows (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash flows from operating activities:
Net income	$ 845	$ 1,129
Less: Income (loss) from discontinued operations	(3)	4
Income from continuing operations	848	1,125
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	1,288	1,127
Regulatory impacts of net nuclear decommissioning trust earnings	131	106
Other amortization	112	90
Stock-based compensation	22	20
Equity in income from unconsolidated affiliates - net	(68)	(101)
Distributions from unconsolidated entities	52	76
Deferred income taxes and investment tax credits	373	414
Proceeds from U.S. treasury grants	310	92
Income from leveraged leases	(4)	(3)
Changes in operating assets and liabilities:
Receivables	(205)	(184)
Inventory	(20)	(27)
Margin and collateral deposits - net of collateral received	6	32
Prepaid taxes	318	33
Other current assets	(319)	(224)
Rent payments in excess of levelized rent expense	(133)	(148)
Accounts payable	178	28
Accrued taxes	76	(23)
Other current liabilities	(189)	(129)
Derivative assets and liabilities - net	137	1,079
Regulatory assets and liabilities - net	(73)	(530)
Other assets	(14)	(40)
Other liabilities	1	(67)
Operating cash flows from discontinued operations	(3)	4
Net cash provided by operating activities	2,824	2,750
Cash flows from financing activities:
Long-term debt issued	686	1,652
Long-term debt issuance costs	(24)	(35)
Long-term debt repaid	(97)	(371)
Bonds purchased	(86)	0
Preference stock issued - net	123	0
Short-term debt financing - net	573	13
Settlements of stock-based compensation - net	(14)	(7)
Dividends and distributions to noncontrolling interests	(43)	(39)
Dividends paid	(313)	(308)
Net cash provided by financing activities	805	905
Cash flows from investing activities:
Capital expenditures	(3,491)	(3,129)
Purchase of interest in acquired companies	(3)	(4)
Proceeds from sale of nuclear decommissioning trust investments	2,108	903
Purchases of nuclear decommissioning trust investments and other	(2,254)	(1,036)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment	6	35
Investments in other assets	0	3
Effect of consolidation and deconsolidation of variable interest entities	0	(91)
Net cash used by investing activities	(3,634)	(3,319)
Net increase (decrease) in cash and cash equivalents	(5)	336
Cash and cash equivalents, beginning of period	1,389	1,673
Cash and cash equivalents, end of period	$ 1,384	$ 2,009

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Third-Party Power Purchase Agreements

During the nine months ended September 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: $116 million each year in 2012 – 2015 and $1.9 billion for the period remaining thereafter.

In October 2011, SCE completed its 2011 annual request for offers and entered into new power purchase contracts with commitments estimated to be: $5 million in 2012, $81 million in 2013, $178 million in 2014 and $240 million in 2015.

Other Commitments

Firm Transmission Commitments

During the nine months ended September 30, 2011, SCE had a firm transmission agreement with additional commitments estimated to be: $1 million in 2011, $4 million each year in 2012 – 2015 and $78 million for the period remaining thereafter.

Fuel Supply Contracts and Coal Transportation Agreements

At September 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, together with estimated transportation costs under existing agreements, are estimated to aggregate $925 million, which consists of: $245 million for the remainder of 2011, $332 million in 2012, $198 million in 2013 and $150 million in 2014.

Turbine Commitments

Based upon a June 2011 contract amendment, EMG was required to schedule turbine deliveries by September 2011 or incur a termination obligation equal to its turbine deposit of $29 million. Under the terms of a September 2011 contract amendment, EMG scheduled turbine deliveries for the Broken Bow I wind project which will utilize the $29 million turbine deposit. In October 2011, EMG entered into a contractual agreement for the purchase of additional turbines with commitments of $39 million through 2012 for the Crofton Bluffs wind 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, which commenced on October 8, 2010, if it has not elected to deploy the additional turbines and if certain other criteria apply.

Capital Commitments

At September 30, 2011, EMG's subsidiaries had firm commitments to spend approximately $157 million during the remainder of 2011, $235 million in 2012 and $19 million in 2013 for capital expenditures. These expenditures primarily relate to the Walnut Creek project 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 230 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at September 30, 2011. Midwest Generation had recorded a liability of $55 million at September 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 September 30, 2011, EME had recorded a liability of $43 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. Under these tax indemnity agreements, the lessees in the sale-leaseback transactions agreed to indemnify the lessors for specified adverse tax consequences that could result from certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. Although the Collins Station lease terminated in April 2004, Midwest Generation's indemnities in favor of its former lease equity investors are still in effect. EME provided similar indemnities in the sale-leaseback transactions related to the Powerton and Joliet Stations in Illinois. 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.

EME agreed to indemnify the lessors in the sale-leaseback transaction related to the Homer City plant for certain negative federal income tax consequences should the rent payments be “levelized” for tax purposes and for potential foreign tax credit losses in the event that the lessor's debt is characterized as recourse, rather than non-recourse. This indemnity covers a limited range of possible tax consequences that are unrelated to performance under the lease.

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. A motion filed by the plaintiffs requesting that the dismissals be certified as “partial final judgments” capable of appeal, and requesting that the remaining claims be stayed pending such an appeal, is pending.

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 sought to have their suits certified as a class action and requested injunctive relief, as well as compensatory and punitive damages. In October 2011, the complaints were dismissed for lack of federal jurisdiction. EME does not know whether the plaintiffs will appeal the dismissal or file a complaint in state court.

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 alleged 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 called for an injunction ordering Homer City to install controls sufficient to meet BACT emission rates at all units subject to the complaint and for other remedies. The Pennsylvania Department of Environmental Protection, the State of New York and the State of New Jersey 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 sought to have their suit certified as a class action and requested injunctive relief, the funding of a health assessment study and medical monitoring, as well as compensatory and punitive damages.

On October 12, 2011, all of the claims in the US EPA's lawsuit were dismissed with prejudice. On October 13, 2011, the claims in the purported class action lawsuit that were based on the federal CAA were dismissed with prejudice, while state law statutory and common law claims were dismissed without prejudice to re-file in state court should the plaintiffs choose to do so. EME does not know whether the US EPA and the other plaintiffs in these cases will appeal the dismissal of these cases, or whether plaintiffs in the purported class action lawsuit will file a complaint in state court. If the plaintiffs are able to revive the lawsuits, 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.

Four Corners New Source Review Litigation

In October 2011, four private environmental organizations filed a CAA citizens' lawsuit against the co-owners of Four Corners. The complaint alleges that certain work performed at the Four Corners generating units 4 and 5, over the approximate periods of 1985-1986 and 2007-present, constituted plant “major modifications” for which the plant should have, but did not, obtain permits and install BACT in violation of the PSD requirements and of the New Source Performance Standards of the CAA. The complaint also alleges subsequent and continuing violation of BACT air emissions limits. The lawsuit seeks injunctive and declaratory relief, civil penalties, including a mitigation project and litigation costs. In November 2010, SCE entered into an agreement to sell its ownership interest in generating units 4 and 5 to APS. The sale is subject to regulatory approvals and is expected to close in late 2012. Under the agreement SCE would remain responsible for its pro rata share of certain environmental liabilities, including penalties arising from environmental violations prior to the sale, but SCE would not be liable for any costs of installing BACT or other costs related to continuing or extending Four Corners operations. SCE cannot predict the outcome of these matters or estimate the impact on its financial statements.

Concurrently, the US EPA has proposed a regional haze federal implementation plan based on an APS proposal that would require shut down of units 1, 2 and 3 by 2016 and the installation of selective catalytic reduction technology on units 4 and 5 by 2018. APS' proposal contemplated that these actions would both satisfy the federal regional haze requirements and resolve any New Source Review claims the US EPA might have. A final federal implementation plan is expected in early 2012.

Malibu Fire Order Instituting Investigation ("OII")

Following a 2007 wildfire in Malibu, California, the CPUC issued an OII to determine if any statutes, CPUC general orders, rules or regulations were violated by SCE or telecomm providers (“OII Respondents”) that shared the use of three failed power poles in the wildfire area. The CPUC's Consumer Protection and Safety Division (“CPSD”) has alleged, among other things, that the poles were overloaded, that the OII Respondents violated the CPUC's rules governing the design, construction and inspection of poles and misled the CPUC during its investigation of the fire, and that SCE failed to preserve evidence relevant to the investigation. In October 2011, the CPSD proposed that the OII Respondents be assessed penalties of approximately $99 million, with SCE being allocated approximately $50 million of the total. SCE has denied the allegations and believes the proposed penalties are excessive. CPSD's allegations will likely be set for hearing in the first quarter of 2012. SCE cannot predict the amount, if any, of penalties that the CPUC may ultimately impose on SCE.

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. Pursuant to the settlement, the Navajo Nation lawsuit was dismissed. The settlement agreement reached with the Navajo Nation did not have a material impact on SCE's financial statements.

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 September 30, 2011, Edison International's recorded estimated minimum liability to remediate its 27 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 (3 sites primarily related to Midwest Generation) was $60 million, of which $51 million was related to SCE, including $15 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 $195 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 $18 million of its recorded liability. SCE has recorded a regulatory asset of $50 million at September 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 $7 million to $17 million. Costs incurred for the nine months ended September 30, 2011 and 2010, were $9 million and $7 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 DOE's appeal of the decision was denied in August 2011. Additional legal action would be necessary to recover damages incurred after December 31, 2005. Any damages recovered are subject to CPUC review as to what amounts 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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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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Regulatory Assets and Liabilities (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Regulatory Assets
Regulatory Assets, Current	$ 454	$ 378
Regulatory asset, Long-term	4,486	4,347
Total Regulatory Assets	4,940	4,725
Regulatory Liabilities
Regulatory Liabilities, Current	734	738
Regulatory Liabilities, Long-term	4,481	4,524
Total Regulatory Liabilities	5,215	5,262
Regulatory balancing accounts, current assets
Regulatory Assets
Regulatory Assets, Current	191	213
Regulatory asset, Long-term	62	56
Energy derivatives
Regulatory Assets
Regulatory Assets, Current	262	162
Regulatory asset, Long-term	214	177
Other:
Regulatory Assets
Regulatory Assets, Current	1	3
Regulatory asset, Long-term	299	280
Regulatory Liabilities
Regulatory Liabilities, Current	6	5
Regulatory Liabilities, Long-term	1
Deferred income taxes - net
Regulatory Assets
Regulatory asset, Long-term	1,938	1,855
Pensions and other postretirement benefits
Regulatory Assets
Regulatory asset, Long-term	1,084	1,097
Unamortized generation investment - net
Regulatory Assets
Regulatory asset, Long-term	323	355
Unamortized loss on reacquired debt
Regulatory Assets
Regulatory asset, Long-term	253	268
Nuclear-related ARO investment - net
Regulatory Assets
Regulatory asset, Long-term	160	154
Unamortized distribution investment - net
Regulatory Assets
Regulatory asset, Long-term	153	105
Costs of removal
Regulatory Liabilities
Regulatory Liabilities, Long-term	2,663	2,623
ARO
Regulatory Liabilities
Regulatory Liabilities, Long-term	944	1,099
Regulatory balancing accounts, liabilities
Regulatory Liabilities
Regulatory Liabilities, Current	728	733
Regulatory Liabilities, Long-term	$ 873	$ 802

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Supplemental Cash Flows Information (Tables)

9 Months Ended

Sep. 30, 2011

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flows Information

	Nine months ended September 30,
(in millions)	2011			2010
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	529		$	486
Tax payments (refunds) – net	(330		)	44
Noncash investing and financing activities:
Accrued capital expenditures	$	393		$	421
Details of debt exchange:
Pollution-control bonds redeemed	$	(86	)	$	(303	)
Pollution-control bonds issued	86			303
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	12			9

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Preferred and Preference Stock of Utility

9 Months Ended

Sep. 30, 2011

Preferred And Preference Stock Of Utility Disclosure [Abstract]

Preferred and Preference Stock of Utility

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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Consolidated Statements of Income (USD $) In Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Electric utility	$ 3,385	$ 3,097	$ 8,060	$ 7,502
Competitive power generation	596	691	1,686	1,838
Total operating revenue	3,981	3,788	9,746	9,340
Fuel	352	328	866	877
Purchased power	1,264	1,118	2,422	2,337
Operations and maintenance	1,119	1,102	3,531	3,287
Depreciation, decommissioning and amortization	436	378	1,288	1,127
Total operating expenses	3,171	2,926	8,107	7,628
Operating income	810	862	1,639	1,712
Interest and dividend income	4	4	38	27
Equity in income from unconsolidated affiliates - net	56	62	68	101
Other income	27	33	110	103
Interest expense	(203)	(175)	(601)	(518)
Other expenses	(11)	(12)	(37)	(39)
Income from continuing operations before income taxes	683	774	1,217	1,386
Income tax expense (benefit)	242	247	369	261
Income from continuing operations	441	527	848	1,125
Income (loss) from discontinued operations, net of tax	0	(4)	(3)	4
Net income	441	523	845	1,129
Dividends on preferred and preference stock of utility	15	13	44	39
Other noncontrolling interests	0	0	(1)	0
Net income attributable to Edison International common shareholders	426	510	802	1,090
Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	426	514	805	1,086
Income (loss) from discontinued operations, net of tax	0	(4)	(3)	4
Net income attributable to Edison International common shareholders	$ 426	$ 510	$ 802	$ 1,090
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)	$ 1.31	$ 1.57	$ 2.47	$ 3.32
Discontinued operations (in dollars per share)	$ 0.00	$ (0.01)	$ (0.01)	$ 0.01
Total (in dollars per share)	$ 1.31	$ 1.56	$ 2.46	$ 3.33
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	328	329	328
Continuing operations (in dollars per share)	$ 1.30	$ 1.57	$ 2.46	$ 3.30
Discontinued operations (in dollars per share)	$ 0.00	$ (0.01)	$ (0.01)	$ 0.01
Total (in dollars per share)	$ 1.30	$ 1.56	$ 2.45	$ 3.31
Dividends declared per common share (in dollars per share)	$ 0.320	$ 0.315	$ 0.960	$ 0.945

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Other Investments (Tables)

9 Months Ended

Sep. 30, 2011

Regulated Entity, Other Assets, Noncurrent [Abstract]

Amortized cost and fair value of the trust investments:

		Amortized Cost				Fair Value
(in millions)	Longest Maturity Dates	September 30, 2011		December 31, 2010		September 30, 2011		December 31, 2010
Stocks	—	$	861	$	895	$	1,721	$	2,029
Municipal bonds	2051	644		706		767		790
U.S. government and agency securities	2041	445		270		501		288
Corporate bonds	2054	266		288		318		346
Short-term investments and receivables/payables	One-year	81		26		86		27
Total		$	2,297	$	2,185	$	3,393	$	3,480

Summary of changes in the fair value of trust

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Balance at beginning of period	$	3,657		$	3,083		$	3,480		$	3,140
Realized gains – net	41			14			76			48
Unrealized gains (losses) – net	(305		)	233			(199		)	90
Other-than-temporary impairments	(22		)	(5		)	(35		)	(16		)
Interest, dividends, contributions and other	22			22			71			85
Balance at end of period	$	3,393		$	3,347		$	3,393		$	3,347

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Derivative Instruments and Hedging Activities (Details 3) (USD $) In Millions, unless otherwise specified			9 Months Ended			12 Months Ended	9 Months Ended							9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended	3 Months Ended		9 Months Ended			3 Months Ended	9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended				9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Competitive power generation Amortizing interest rate swap Cash flow hedges Derivative Contracts Expiring On May 2013 [Member] Convert Floating Rate Debt To Fixed 0.8135 Percent Rate Debt [Member]	Sep. 30, 2011 Competitive power generation Amortizing interest rate swap Cash flow hedges Derivative Contracts Expiring On May 2013 [Member] Convert Floating Rate Debt To Fixed 0.79 Percent Rate Debt [Member]	Sep. 30, 2011 Competitive power generation Amortizing interest rate swap Cash flow hedges Derivative Contracts Expiring on June, 2016	Dec. 31, 2010 Competitive power generation Amortizing interest rate swap Cash flow hedges Derivative Contracts Expiring on June, 2016	Sep. 30, 2011 Competitive power generation Amortizing interest rate swap Cash flow hedges Derivative Contracts Expiring on December, 2020	Sep. 30, 2011 Competitive power generation Amortizing interest rate swap Cash flow hedges Derivative Contracts Expiring On May 2023 [Member] Convert Floating Rate Debt To Fixed 3.5429 Percent Rate Debt [Member]	Sep. 30, 2011 Competitive power generation Amortizing interest rate swap Cash flow hedges Derivative Contracts Expiring On May 2023 [Member] Convert Floating Rate Debt To Fixed 4.0025 Percent Rate Debt [Member]	Sep. 30, 2011 Competitive power generation Amortizing forward starting interest rate swap Cash flow hedges Derivative Contracts Expiring on June, 2016	Sep. 30, 2011 Competitive power generation Amortizing forward starting interest rate swap Cash flow hedges Derivative Contracts Expiring on December, 2020	Sep. 30, 2011 Competitive power generation Amortizing forward starting interest rate swap Cash flow hedges Derivative Contracts Expiring On May 2023 [Member] Convert Floating Rate Debt To Fixed 3.5429 Percent Rate Debt [Member]	Sep. 30, 2011 Competitive power generation Amortizing forward starting interest rate swap Cash flow hedges Derivative Contracts Expiring On May 2023 [Member] Convert Floating Rate Debt To Fixed 4.0025 Percent Rate Debt [Member]	Sep. 30, 2011 Competitive power generation Amortizing forward starting interest rate swap Cash flow hedges Derivative Contracts Expiring on December, 2025	Dec. 31, 2010 Competitive power generation Amortizing forward starting interest rate swap Cash flow hedges Derivative Contracts Expiring on December, 2025	Sep. 30, 2011 Competitive power generation Amortizing forward starting interest rate swap Cash flow hedges Derivative Contracts Expiring on March, 2026	Dec. 31, 2010 Competitive power generation Amortizing forward starting interest rate swap Cash flow hedges Derivative Contracts Expiring on March, 2026	Sep. 30, 2011 Electric Utility Southern California Edison Company Economic hedges	Sep. 30, 2010 Electric Utility Southern California Edison Company Economic hedges	Sep. 30, 2011 Electric Utility Southern California Edison Company Economic hedges	Sep. 30, 2010 Electric Utility Southern California Edison Company Economic hedges	Dec. 31, 2010 Electric Utility Southern California Edison Company Economic hedges	Sep. 30, 2010 Competitive power generation Edison Mission Group Inc. Cash flow hedges Competitive power generation revenues	Sep. 30, 2011 Competitive power generation Edison Mission Group Inc. Cash flow hedges Competitive power generation revenues	Sep. 30, 2010 Competitive power generation Edison Mission Group Inc. Cash flow hedges Competitive power generation revenues	Sep. 30, 2011 Competitive power generation Economic hedges Competitive power generation revenues	Sep. 30, 2010 Competitive power generation Economic hedges Competitive power generation revenues	Sep. 30, 2011 Competitive power generation Economic hedges Competitive power generation revenues	Sep. 30, 2010 Competitive power generation Economic hedges Competitive power generation revenues	Sep. 30, 2011 Competitive power generation Economic hedges Fuel	Sep. 30, 2010 Competitive power generation Economic hedges Fuel	Sep. 30, 2011 Competitive power generation Economic hedges Fuel	Sep. 30, 2010 Competitive power generation Economic hedges Fuel	Sep. 30, 2011 Competitive power generation Trading activities Operating revenues	Sep. 30, 2010 Competitive power generation Trading activities Operating revenues	Sep. 30, 2011 Competitive power generation Trading activities Operating revenues	Sep. 30, 2010 Competitive power generation Trading activities Operating revenues	Sep. 30, 2011 Southern California Edison Company Economic hedges	Dec. 31, 2010 Southern California Edison Company Economic hedges	Sep. 30, 2011 Cash flow hedges Competitive power generation revenues	Sep. 30, 2010 Cash flow hedges Competitive power generation revenues
Derivatives
Realized loss on economic hedging activities																		$ (58)	$ (53)	$ (132)	$ (116)
Notional amount of derivatives			39	24		138				84	110	398	48	119	122	67	68
Unrealized gain (loss) on economic hedging activities																		(110)	(165)	(433)	(1,022)
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																																								(62)	102
Reclassification to net income																																								(29)	(134)
End of period derivative gains (losses)																																								(64)	143
Unrealized derivative gains after taxes recorded in accumulated other comprehensive income																																								(39)	86
Aggregate fair value of all derivative liabilities with credit-risk-related contingent features																		162		162		67
Collateral already posted, fair value																																							4
Additional collateral, aggregate fair value																																						23
Floating interest rate received			1-month	1-month	6-month	6-month	6-month	3-month	3-month					3-month	3-month	3-month	3-month
Fixed interest rate paid (as a percent)			0.8135%	0.79%	3.175%	3.175%	3.415%	3.5429%	4.0025%					4.29%	4.29%	3.46%	3.46%
Amount of cash flow hedge ineffectiveness																							4	6	5
Gain (loss) on derivative instruments																										(6)	7	20	0	(3)	2	1	0	11	28	68	108
Collateral provided to counterparties:
Offset against derivative liabilities	16	8
Reflected in margin and collateral deposits	53	65
Collateral received from counterparties:
Offset against derivative assets	$ 30	$ 52

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Supplemental Cash Flows Information (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash payments (receipts) for interest and taxes:
Interest - net of amounts capitalized	$ 529	$ 486
Tax payments (refunds)- net	(330)	44
Noncash investing and financing activities:
Accrued capital expenditures	393	421
Details of debt exchange:
Pollution-control bonds redeemed	(86)	(303)
Pollution-control bonds issued	86	303
Consolidation of variable interest entities:
Assets other than cash	0	(94)
Liabilities and noncontrolling interests	0	99
Deconsolidation of variable interest entities:
Assets other than cash	0	380
Liabilities and noncontrolling interests	0	(476)
Dividends declared but not paid:
Common stock.	104	103
Preferred and preference stock	$ 12	$ 9

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Fair Value Measurements (Details 2) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Fair Value of Long-Term Debt Recorded at Carrying Value
Long-term debt, including current portion, carrying amount	$ 13,061	$ 12,419
Long-term debt, including current portion, fair value	$ 13,500	$ 12,360

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Debt and Credit Agreements (Details) (USD $)					1 Months Ended				9 Months Ended	1 Months Ended				1 Months Ended		1 Months Ended				1 Months Ended			1 Months Ended		1 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Letters of Credit	Sep. 30, 2011 Letters of Credit Edison Mission Energy	Feb. 28, 2011 Letters of Credit Viento Funding II, Inc.	Sep. 30, 2011 Short-term debt Edison International	Dec. 31, 2010 Short-term debt Edison International	Sep. 30, 2011 Short-term debt Southern California Edison Company	Sep. 30, 2011 Revolving credit facility Southern California Edison Company	Feb. 28, 2011 Term Loan due 2020 Viento Funding II, Inc.	Feb. 28, 2011 Working capital facility Viento Funding II, Inc.	May 31, 2011 First and refunding mortgage bonds due in 2021 Southern California Edison Company	Oct. 31, 2011 First and refunding mortgage bonds due in 2014 Southern California Edison Company Issuance of Debt [Member]	Jul. 27, 2011 Primary term loan Walnut Creek project	Jul. 29, 2011 Primary term loan Walnut Creek project	Jul. 27, 2011 Second Construction Loan [Member] Walnut Creek project	Jun. 28, 2013 Second Construction Loan [Member] Walnut Creek project	Sep. 30, 2011 Second Construction Loan [Member] Walnut Creek project	Jul. 29, 2011 Second Construction Loan [Member] Walnut Creek project	Sep. 30, 2011 Tax-exempt pollution control bonds Southern California Edison Company	May 31, 2011 Tax-exempt pollution control bonds Southern California Edison Company	Dec. 31, 2010 Southern California Edison Company	Feb. 28, 2011 Viento Funding II, Inc.	Sep. 30, 2011 Viento Funding II, Inc.	Jul. 27, 2011 Walnut Creek project	Sep. 30, 2011 Walnut Creek project	Jul. 29, 2011 Walnut Creek project mW	Nov. 30, 2011 Walnut Creek project Forward swap due 2013	Jul. 29, 2011 Walnut Creek project Forward swap due 2013	Jun. 28, 2013 Walnut Creek project Forward swap due 2023
Debt Instrument:
Bonds issued												$ 500,000,000
Interest rate on debt (as a percent)												3.875%
Debt, face amount					23,000,000					227,000,000	5,000,000		150,000,000										255,000,000
Purchase of tax-exempt bonds subject to remarketing																				30,000,000	56,000,000
Power generating capacity for natural gas-fired peaker plant (in megawatts)																											479
Construction loan																											495,000,000
Letters of credit and working capital facilities																											122,000,000
Letters of Credit Outstanding, Amount									83,000,000																	40,000,000
Debt Instrument, Interest Rate, Effective Percentage																		4.94%
Debt Instrument, Interest Rate at Period End																										2.48%
Project-level construction term loan															442,000,000				53,000,000
Term of Amortizing Loan																									10 years
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%
Maturity period of debt instruments (in years)					7					10	7
Long-term debt - Gross																								216,000,000
Letters of credit outstanding																								23,000,000
Variable rate, incremental spread (as a percent)																							0.25%
Outstanding short-term borrowing	560,000,000	115,000,000				10,000,000	19,000,000	550,000,000														0
Weighted average interest rate (as a percent)						0.60%	0.63%	0.34%
Credit facility									2,400,000,000
Standby letters of credit outstanding			98,000,000	65,000,000
Standby letters of credit expiring in 2011			7,000,000	1,000,000
Standby letters of credit expiring in 2012			63,000,000	64,000,000
Standby letters of credit expiring in 2017			10,000,000
Standby letters of credit expiring in 2018			18,000,000
Derivative, Higher Fixed Interest Rate Range																												0.81%
Derivative, Variable Interest Rate																	8.00%													5.84%
Fixed interest rate paid (as a percent)																	4.00%												0.79%	3.54%
Long-term Construction Loan																		$ 49,000,000								$ 44,000,000
Letter of credit expiration date									twelve months or less

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Commitments and Contingencies (Details 2) (USD $)			9 Months Ended	1 Months Ended	9 Months Ended			1 Months Ended		9 Months Ended	1 Months Ended	9 Months Ended	1 Months Ended	9 Months Ended		1 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Edison International	Jun. 30, 2010 Southern California Edison Company	Sep. 30, 2011 Southern California Edison Company	Sep. 30, 2010 Southern California Edison Company	Sep. 30, 2011 Southern California Edison Company Nuclear Insurance	Oct. 30, 2011 Southern California Edison Company Malibu Fire Order Instituting Investigation [Member] Pending or Threatened Litigation in January 2011	May 31, 2011 Midwest Generation LLC.	Sep. 30, 2011 Midwest Generation LLC.	Aug. 31, 2009 Midwest Generation LLC. Violation of certain operating permit requirements	Sep. 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	Sep. 30, 2011 SCE and other owners of San Onofre and Palo Verde Nuclear Insurance	Sep. 30, 2011 Nuclear Insurance	Oct. 30, 2011 Malibu Fire Order Instituting Investigation [Member] Pending or Threatened Litigation in January 2011	Sep. 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 claims in the complaint filed by the US EPA and the State of Illinois												9
Number of claims 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
Loss Contingency, Damages Sought, Value								50,000,000								99,000,000
Number of plaintiffs													2
Identified material sites for environmental remediation (in number of sites)			27		24					3
Identified material sites, minimum amount of upper end of range of costs			1,000,000
Minimum liability for environmental remediation			60,000,000		51,000,000												15,000,000
Amount that cleanup costs could exceed recorded liability for identified material sites			195,000,000
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					18,000,000
Regulatory asset, Long-term	4,486,000,000	4,347,000,000			50,000,000
Maximum expected period for cleanup of identified sites (in years)					30
Expected annual environmental remediation costs, low end of range					7,000,000
Expected annual environmental remediation costs, high end of range					17,000,000
Environmental remediation costs					9,000,000	7,000,000
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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Other Income and Expenses (Tables)

9 Months Ended

Sep. 30, 2011

Other Income and Expenses [Abstract]

Other Income and Expenses

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2011		2010		2011		2010
Other income:
Equity Available Funds Used During Construction	$	18	$	24	$	74	$	76
Increase in cash surrender value of life insurance policies	6		7		19		19
Other	2		2		10		8
Total utility other income	26		33		103		103
Competitive power generation and other income	1		—		7		—
Total other income	$	27	$	33	$	110	$	103
Other expenses:
Civic, political and related activities and donations	$	6	$	7	$	21	$	21
Other	4		3		14		18
Total utility other expenses	10		10		35		39
Competitive power generation and other expenses	1		2		2		—
Total other expenses	$	11	$	12	$	37	$	39