10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________

FORM 10-Q

________________________

(Mark One)
R	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2012
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from                        to

Commission File Number 1-9936

_________________________

EDISON INTERNATIONAL

(Exact name of registrant as specified in its charter)

__________________________

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

__________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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 30, 2012
Common Stock, no par value	325,811,206

TABLE OF CONTENTS

GLOSSARY			iv
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS			2
	Consolidated Statements of Income		2
	Consolidated Statements of Comprehensive Income		3
	Consolidated Balance Sheets		4
	Consolidated Statements of Cash Flows		6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS			8
	Note 1. Summary of Significant Accounting Policies		8
	Note 2. Consolidated Statements of Changes in Equity		11
	Note 3. Variable Interest Entities		12
	Note 4. Fair Value Measurements		14
	Note 5. Debt and Credit Agreements		19
	Note 6. Derivative Instruments and Hedging Activities		21
	Note 7. Income Taxes		26
	Note 8. Compensation and Benefit Plans		28
	Note 9. Commitments and Contingencies		29
	Note 10. Environmental Developments		37
	Note 11. Accumulated Other Comprehensive Loss		37
	Note 12. Supplemental Cash Flows Information		38
	Note 13. Preferred and Preference Stock of Utility		38
	Note 14. Regulatory Assets and Liabilities		39
	Note 15. Other Investments		40
	Note 16. Other Income and Expenses		41
	Note 17. Planned Sale of Interest in Four Corners		41
	Note 18. Discontinued Operations		41
	Note 19. EME Liquidity and Restructuring Activities		42
	Note 20. Business Segments		43
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			44
FORWARD-LOOKING STATEMENTS			44
EDISON INTERNATIONAL OVERVIEW			46
	Highlights of Operating Results		46
	Management Overview of SCE		47
		2012 CPUC General Rate Case	47
		2013 Cost of Capital Application	47
		San Onofre	47
		Capital Program	51
	Management Overview of EMG		51
		EME Liquidity and Restructuring Activities	51
		Midwest Generation's Dependence on EME	52
		Midwest Generation Environmental Compliance Plans and Costs	53
		Homer City Lease	53
	Environmental Developments		54
SOUTHERN CALIFORNIA EDISON COMPANY			55
RESULTS OF OPERATIONS			55
	Three Months Ended September 30, 2012 versus September 30, 2011		56

i

	Nine Months Ended September 30, 2012 versus September 30, 2011	57
	Supplemental Operating Revenue Information	58
	Income Taxes	59
LIQUIDITY AND CAPITAL RESOURCES		59
	Available Liquidity	59
	Capital Investment Plan	60
	Regulatory Proceedings	60
	Dividend Restrictions	60
	Margin and Collateral Deposits	60
	Workers Compensation Self-Insurance Fund	61
	Historical Segment Cash Flows	61
	Contractual Obligations and Contingencies	62
MARKET RISK EXPOSURES		62
	Commodity Price Risk	63
	Credit Risk	63
EDISON MISSION GROUP		64
RESULTS OF OPERATIONS		64
LIQUIDITY AND CAPITAL RESOURCES		71
	Available Liquidity	71
	Capital Investment Plan	71
	Historical Segment Cash Flows	72
	Credit Ratings	74
	Margin, Collateral Deposits and Other Credit Support for Energy Contracts	74
	Intercompany Tax Allocation Agreement	74
	Debt Covenants and Dividend Restrictions	75
	Contractual Obligations and Contingencies	75
	Off-Balance Sheet Transactions	75
	Environmental Matters and Regulations	75
MARKET RISK EXPOSURES		76
	Derivative Instruments	76
	Commodity Price Risk	76
	Credit Risk	78
	Interest Rate Risk	79
EDISON INTERNATIONAL PARENT AND OTHER		80
RESULTS OF OPERATIONS		80
LIQUIDITY AND CAPITAL RESOURCES		80
	Historical Segment Cash Flows	80
EDISON INTERNATIONAL (CONSOLIDATED)		81
LIQUIDITY AND CAPITAL RESOURCES		81
	Contractual Obligations	81
CRITICAL ACCOUNTING ESTIMATES AND POLICIES		81
NEW ACCOUNTING GUIDANCE		81
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		81
ITEM 4. CONTROLS AND PROCEDURES		81
	Disclosure Controls and Procedures	81
	Changes in Internal Control Over Financial Reporting	81
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS		82
	Midwest Generation New Source Review and Other Litigation	82
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		82

ii

	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	82
ITEM 6. EXHIBITS		83
SIGNATURE		84

iii

GLOSSARY

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

2011 Form 10-K	Edison International's Annual Report on Form 10-K for the year-ended December 31, 2011
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
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
GECC	General Electric Capital Corporation
GHG	greenhouse gas
GRC	general rate case
GWh	gigawatt-hours

iv

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
Homer City MTA	Master Transaction Agreement between EME Homer City Generation L.P. and General Electric Capital Corporation
Illinois EPA	Illinois Environmental Protection Agency
IRS	Internal Revenue Service
ISO	Independent System Operator
kWh(s)	kilowatt-hour(s)
LIBOR	London Interbank Offered Rate
MATS	Mercury and Air Toxics Standards
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

v

SCE	Southern California Edison Company
SNCR	selective non-catalytic reduction
SDG&E	San Diego Gas & Electric
SEC	U.S. Securities and Exchange Commission
SIP(s)	state implementation plan(s)
SO2	sulfur dioxide
US EPA	U.S. Environmental Protection Agency
VIE(s)	variable interest entity(ies)

vi

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1

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)	2012			2011			2012			2011
Electric utility	$	3,730		$	3,385		$	8,791		$	8,060
Competitive power generation	340			437			1,009			1,277
Total operating revenue	4,070			3,822			9,800			9,337
Fuel	270			272			678			671
Purchased power	1,612			1,264			3,049			2,422
Operation and maintenance	1,152			1,071			3,450			3,325
Depreciation, decommissioning and amortization	465			430			1,389			1,272
(Gain) loss on sale of assets and other	(65		)	—			(60		)	8
Total operating expenses	3,434			3,037			8,506			7,698
Operating income	636			785			1,294			1,639
Interest and dividend income	3			4			19			38
Equity in income from unconsolidated affiliates, net	25			56			42			68
Other income	37			27			105			110
Interest expense	(214		)	(203		)	(643		)	(600		)
Other expenses	(10		)	(11		)	(36		)	(37		)
Income from continuing operations before income taxes	477			658			781			1,218
Income tax expense	181			232			217			370
Income from continuing operations	296			426			564			848
Income (loss) from discontinued operations, net of tax	(76		)	15			(129		)	(3		)
Net income	220			441			435			845
Dividends on preferred and preference stock of utility	25			15			66			44
Other noncontrolling interests	5			—			12			(1		)
Net income attributable to Edison International common shareholders	$	190		$	426		$	357		$	802
Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	$	266		$	411		$	486		$	805
Income (loss) from discontinued operations, net of tax	(76		)	15			(129		)	(3		)
Net income attributable to Edison International common shareholders	$	190		$	426		$	357		$	802
Basic earnings (loss) per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding	326			326			326			326
Continuing operations	$	0.81		$	1.26		$	1.49		$	2.47
Discontinued operations	(0.23		)	0.05			(0.40		)	(0.01		)
Total	$	0.58		$	1.31		$	1.09		$	2.46
Diluted earnings (loss) per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities	329			329			328			329
Continuing operations	$	0.81		$	1.25		$	1.48		$	2.46
Discontinued operations	(0.23		)	0.05			(0.39		)	(0.01		)
Total	$	0.58		$	1.30		$	1.09		$	2.45
Dividends declared per common share	$	0.325		$	0.320		$	0.975		$	0.960

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

2

Consolidated Statements of Comprehensive Income							Edison International
	Three months ended September 30,						Nine months ended September 30,
(in millions, unaudited)	2012			2011			2012			2011
Net income	$	220		$	441		$	435		$	845
Other comprehensive income (loss), net of tax:
Pension and postretirement benefits other than pensions:
Net loss arising during the period, net of income tax benefit of $3 for the nine months ended September 30, 2012	—			—			(3		)	—
Amortization of net loss included in net income, net of income tax expense of $2 and $1 for the three months and $7 and $4 for the nine months ended September 30, 2012 and 2011, respectively	4			3			12			7
Unrealized loss on derivatives qualified as cash flow hedges:
Unrealized holding loss arising during the period, net of income tax benefit of $11 and $19 for the three months and $13 and $24 for the nine months ended September 30, 2012 and 2011, respectively	(16		)	(30		)	(19		)	(38		)
Reclassification adjustments included in net income, net of income tax expense (benefit) of $1 and none for the three months and $(12) and $(12) for the nine months ended September 30, 2012 and 2011, respectively	1			—			(19		)	(17		)
Other comprehensive loss	(11		)	(27		)	(29		)	(48		)
Comprehensive income	209			414			406			797
Less: Comprehensive income attributable to noncontrolling interests	30			15			78			43
Comprehensive income attributable to Edison International	$	179		$	399		$	328		$	754

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

3

Consolidated Balance Sheets	Edison International
(in millions, unaudited)	September 30, 2012		December 31, 2011
ASSETS
Cash and cash equivalents	$	1,080	$	1,390
Receivables, less allowances of $75 for uncollectible accounts at both dates	1,167		908
Accrued unbilled revenue	787		519
Inventory	508		519
Prepaid taxes	36		88
Derivative assets	76		106
Restricted cash and cash equivalents	116		103
Margin and collateral deposits	88		58
Regulatory assets	250		494
Deferred income taxes	231		—
Other current assets	94		92
Assets of discontinued operations	61		207
Total current assets	4,494		4,484
Nuclear decommissioning trusts	3,997		3,592
Investments in unconsolidated affiliates	544		525
Other investments	189		211
Total investments	4,730		4,328
Utility property, plant and equipment, less accumulated depreciation of $7,378 and $6,894 at respective dates	29,314		27,569
Competitive power generation and other property, plant and equipment, less accumulated depreciation of $1,616 and $1,408 at respective dates	4,544		4,547
Total property, plant and equipment	33,858		32,116
Derivative assets	117		131
Restricted deposits	89		25
Rent payments in excess of levelized rent expense under plant operating leases	855		760
Regulatory assets	5,677		5,466
Other long-term assets	725		684
Total long-term assets	7,463		7,066
Assets of discontinued operations	—		45
Total assets	$	50,545	$	48,039

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

4

Consolidated Balance Sheets	Edison International
(in millions, except share amounts, unaudited)	September 30, 2012			December 31, 2011
LIABILITIES AND EQUITY
Short-term debt	$	429		$	429
Current portion of long-term debt	565			57
Accounts payable	1,257			1,397
Accrued taxes	105			52
Accrued interest	207			205
Customer deposits	193			199
Derivative liabilities	109			268
Regulatory liabilities	493			670
Deferred income taxes	—			91
Other current liabilities	855			953
Liabilities of discontinued operations	61			27
Total current liabilities	4,274			4,348
Long-term debt	13,708			13,689
Deferred income taxes	5,745			5,396
Deferred investment tax credits	108			89
Customer advances	149			138
Derivative liabilities	717			547
Pensions and benefits	2,884			2,912
Asset retirement obligations	2,804			2,680
Regulatory liabilities	5,249			4,670
Other deferred credits and other long-term liabilities	2,887			2,475
Total deferred credits and other liabilities	20,543			18,907
Liabilities of discontinued operations	—			9
Total liabilities	38,525			36,953
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)	2,385			2,360
Accumulated other comprehensive loss	(168		)	(139		)
Retained earnings	7,806			7,834
Total Edison International's common shareholders' equity	10,023			10,055
Preferred and preference stock of utility	1,759			1,029
Other noncontrolling interests	238			2
Total noncontrolling interests	1,997			1,031
Total equity	12,020			11,086
Total liabilities and equity	$	50,545		$	48,039

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)	2012			2011
Cash flows from operating activities:
Net income	$	435		$	845
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	1,389			1,272
Regulatory impacts of net nuclear decommissioning trust earnings	147			131
Other amortization	73			112
Gain on sale of assets and other	(60		)	6
Stock-based compensation	28			22
Equity in income from unconsolidated affiliates	(42		)	(68		)
Distributions from unconsolidated affiliates	15			52
Deferred income taxes and investment tax credits	(20		)	373
Income from leveraged leases	(4		)	(4		)
Proceeds from U.S. treasury grants	73			310
Changes in operating assets and liabilities:
Receivables	(293		)	(205		)
Inventory	11			(25		)
Margin and collateral deposits, net of collateral received	(31		)	6
Prepaid taxes	52			318
Other current assets	(264		)	(321		)
Rent payments in excess of levelized rent expense	(95		)	(96		)
Accounts payable	347			178
Accrued taxes	61			76
Other current liabilities	(87		)	(189		)
Derivative assets and liabilities, net	(8		)	137
Regulatory assets and liabilities, net	210			(73		)
Other assets	(30		)	(20		)
Other liabilities	256			1
Operating cash flows from continuing operations	2,163			2,838
Operating cash flows from discontinued operations, net	(5		)	(14		)
Net cash provided by operating activities	2,158			2,824
Cash flows from financing activities:
Long-term debt issued	549			686
Long-term debt issuance costs	(12		)	(24		)
Long-term debt repaid	(36		)	(97		)
Bonds purchased	—			(86		)
Preference stock issued, net	804			123
Preference stock redeemed	(75		)	—
Short-term debt financing, net	(10		)	573
Settlements of stock-based compensation, net	(45		)	(14		)
Cash contributions from noncontrolling interests	238			—
Dividends and distributions to noncontrolling interests	(75		)	(43		)
Dividends paid	(318		)	(313		)
Net cash provided by financing activities from continuing operations	$	1,020		$	805

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

6

Consolidated Statements of Cash Flows	Edison International
	Nine months ended September 30,
(in millions, unaudited)	2012			2011
Cash flows from investing activities:
Capital expenditures	$	(3,371	)	$	(3,481	)
Purchase of interest in acquired companies	—			(3		)
Proceeds from sale of nuclear decommissioning trust investments	1,525			2,108
Purchases of nuclear decommissioning trust investments and other	(1,689		)	(2,254		)
Proceeds from sale of interest in project, net	107			—
Proceeds from partnerships and unconsolidated subsidiaries, net of investment	7			6
Restricted deposits and restricted cash and cash equivalents	(75		)	4
Customer advances for construction and other investments	3			(4		)
Investing cash flows from continuing operations	(3,493		)	(3,624		)
Investing cash flows from discontinued operations, net	(19		)	(10		)
Net cash used by investing activities	(3,512		)	(3,634		)
Net (decrease) increase in cash and cash equivalents from continuing operations	(310		)	19
Cash and cash equivalents at beginning of period from continuing operations	1,390			1,261
Cash and cash equivalents at end of period from continuing operations	$	1,080		$	1,280
Net decrease in cash and cash equivalents from discontinued operations	$	(24	)	$	(24	)
Cash and cash equivalents at beginning of period from discontinued operations	79			128
Cash and cash equivalents at end of period from discontinued operations	$	55		$	104

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

7

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 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 2011 Form 10-K. The same accounting policies are followed for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2012, discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2011 Form 10-K.

In the opinion of management, all adjustments, consisting of recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and nine-month periods ended September 30, 2012 are not necessarily indicative of the operating results for the full year.

The December 31, 2011 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Interim Financial Statements

On September 21, 2012, EME Homer City Generation L.P. ("Homer City") and Homer City Generation L.P., an affiliate of General Electric Capital Corporation ("GECC"), entered into a Master Transaction Agreement ("Homer City MTA") for the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities.

Beginning in the third quarter of 2012, Homer City met the definition of a discontinued operation and was classified separately in Edison International's consolidated financial statements. Previously issued financial statements have been restated to reflect discontinued operations reported subsequent to the original issuance date. For further information, see Note 18—Discontinued Operations. Except as indicated, amounts in the notes to the consolidated financial statements relate to continuing operations of Edison International.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $933 million and $1.3 billion at September 30, 2012 and December 31, 2011, respectively. Generally, the carrying value of cash equivalents equals the fair value, as these investments have original 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 $234 million and $220 million of checks issued, but not yet paid by the financial institution, from cash to accounts payable at September 30, 2012 and December 31, 2011, respectively.

Restricted Cash and Cash Equivalents, and Restricted Deposits

Restricted cash and cash equivalents at September 30, 2012 and December 31, 2011 included $97 million received from a wind project financing that was held in escrow at those dates. At September 30, 2012, restricted deposits included $48 million to support outstanding letters of credit issued under EME's letter of credit facilities.

8

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, 2012		December 31, 2011
Coal, gas, fuel oil and other raw materials	$	138	$	143
Spare parts, materials and supplies	370		376
Total inventory	$	508	$	519

Revenue Recognition

Electric Utility Revenue

Operating revenue is recognized when electricity is delivered and includes amounts for services rendered but unbilled at the end of each reporting period. During the first nine months of 2012, pending the outcome of the 2012 GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement included in customer rates. A GRC memorandum account has been established for SCE, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.

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)	2012		2011		2012		2011
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	266	$	411	$	486	$	805
Participating securities dividends	—		—		—		—
Income from continuing operations available to common shareholders	$	266	$	411	$	486	$	805
Weighted average common shares outstanding	326		326		326		326
Basic earnings per share – continuing operations	$	0.81	$	1.26	$	1.49	$	2.47
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	266	$	411	$	486	$	805
Income impact of assumed conversions	—		2		1		3
Income from continuing operations available to common shareholders and assumed conversions	$	266	$	413	$	487	$	808
Weighted average common shares outstanding	326		326		326		326
Incremental shares from assumed conversions	3		3		2		3
Adjusted weighted average shares – diluted	329		329		328		329
Diluted earnings per share – continuing operations	$	0.81	$	1.25	$	1.48	$	2.46

Stock-based compensation awards to purchase 3,238,581 and 5,943,378 shares of common stock for the three months ended September 30, 2012 and 2011, respectively, and 4,819,683 and 8,970,290 shares of common stock for the nine months ended September 30, 2012 and 2011, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares and therefore, the effect would have been antidilutive.

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New Accounting Guidance

Accounting Guidance Adopted in 2012

Fair Value Measurement

In May 2011, the Financial Accounting Standards Board ("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 adopted this guidance effective January 1, 2012. For further information, see Note 4.

Presentation of Comprehensive Income

In June 2011 and December 2011, the FASB issued accounting standards updates 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 adopted this guidance January 1, 2012, and elected to present two separate but consecutive statements. The adoption of these accounting standards updates did not change the items that constitute net income and other comprehensive income.

Accounting Guidance Not Yet Adopted

Offsetting Assets and Liabilities

In December 2011, the FASB issued an accounting standards update modifying the disclosure requirements about the nature of an entity's rights of offsetting assets and liabilities in the statement of financial position under master netting agreements and related arrangements associated with financial and derivative instruments. The guidance requires increased disclosure of the gross and net recognized assets and liabilities, collateral positions and narrative descriptions of setoff rights. Edison International will adopt this guidance effective January 1, 2013.

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Note 2.    Consolidated Statements of Changes in Equity

The following table provides the changes in equity for the nine months ended September 30, 2012.

	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, 2011	$	2,360		$	(139	)	$	7,834		$	10,055		$	2		$	1,029		$	11,086
Net income	—			—			357			357			12			66			435
Other comprehensive loss	—			(29		)	—			(29		)	—			—			(29		)
Contributions from noncontrolling interests1	—			—			—			—			238			—			238
Transfer of assets to Capistrano Wind Partners2	(21		)	—			—			(21		)	—			—			(21		)
Common stock dividends declared ($0.975 per share)	—			—			(318		)	(318		)	—			—			(318		)
Dividends, distributions to noncontrolling interests and other	—			—			—			—			(14		)	(66		)	(80		)
Stock-based compensation and other	19			—			(64		)	(45		)	—			—			(45		)
Noncash stock-based compensation and other	27			—			(2		)	25			—			—			25
Issuance of preference stock	—			—			—			—			—			804			804
Redemption of preference stock	—			—			(1		)	(1		)	—			(74		)	(75		)
Balance at September 30, 2012	$	2,385		$	(168	)	$	7,806		$	10,023		$	238		$	1,759		$	12,020

¹  Funds contributed by third-party investors related to the Capistrano Wind equity capital raise are reported in noncontrolling interest. For further information, see Note 3.

²  Common stock was reduced by $21 million during the nine months ended September 30, 2012 due to a new tax basis in the assets transferred to Capistrano Wind Partners. For further information, see Note 3.

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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 interest1	(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.

Note 3.    Variable Interest Entities

Categories of Variable Interest Entities

Projects or Entities that are Consolidated

At September 30, 2012 and December 31, 2011, 16 and 13 wind projects were consolidated with a total generating capacity of 861 MW and 570 MW, respectively, that have noncontrolling interests held by others. The increase from the projects consolidated after December 31, 2011 was due to the Capistrano Wind equity capital transaction discussed below. In determining that Edison International's subsidiary, EME, was the primary beneficiary of the projects that are consolidated, key factors considered were EME's ability to direct commercial and operating activities and EME's obligation to absorb losses of the variable interest entities.

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

(in millions)	September 30, 2012		December 31, 2011
Current assets	$	71	$	36
Net property, plant and equipment	1,090		675
Other long-term assets	73		5
Total assets	$	1,234	$	716
Current liabilities	$	40	$	28
Long-term debt net of current portion	172		57
Deferred revenues	172		69
Long-term derivative liabilities	23		—
Other long-term liabilities	38		22
Total liabilities	$	445	$	176
Noncontrolling interests	$	238	$	2

Assets serving as collateral for the debt obligations had a carrying value of $467 million and $136 million at September 30, 2012 and December 31, 2011, respectively, and primarily consist of property, plant and equipment.

Capistrano Wind Equity Capital

On February 13, 2012, Edison Mission Wind Inc. ("Edison Mission Wind") sold its indirect equity interests in the Cedro Hill wind project (150 MW in Texas), the Mountain Wind Power I project (61 MW in Wyoming) and the Mountain Wind Power II project (80 MW in Wyoming) to a new venture, Capistrano Wind Partners. Outside investors provided $238 million of the funding. Capistrano Wind Partners also agreed to acquire the Broken Bow I wind project (80 MW in Nebraska) and the Crofton Bluffs wind project (40 MW in Nebraska) for consideration expected to include $140 million from the same outside investors upon the satisfaction of specified conditions, including commencement of commercial operation and conversion of project debt financing to term loans. In March 2012, EME received a distribution of the proceeds from outside investors, which was used for general corporate purposes. Through their ownership of Capistrano Wind Holdings, an indirect subsidiary of EME, Edison Mission Wind, and EME's parent company, Mission Energy Holding Company ("MEHC"), own 100% of the Class A equity interests in Capistrano Wind Partners, and the Class B preferred equity interests are held by outside investors. Under the terms of the formation documents, preferred equity interests receive 100% of the cash available for distribution, up to a scheduled amount to target a certain return and thereafter cash distributions are shared. Cash available for distribution includes 90% of the tax benefits realized by MEHC and contributed to Capistrano Wind Partners.

Edison Mission Wind retains indirect beneficial ownership of the common equity in the projects, net of a $4 million preferred investment made by MEHC, a note receivable of $107 million from the sale of the project companies, and retains responsibilities for managing the operations of Capistrano Wind Holdings and its projects, and accordingly, EME will continue to consolidate these projects. The $238 million contributed by the third-party interests is reflected in "Other noncontrolling interests" on Edison International's consolidated balance sheets at September 30, 2012. This transaction was accounted for as a transfer among entities under common control and, therefore, resulted in no change in the book basis of the transferred assets. However, the transaction triggered a taxable gain and new tax basis in the assets with a corresponding adjustment to deferred taxes and a reduction to equity of $21 million.

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has 17 power purchase agreements ("PPAs") that have variable interests in VIEs, including 7 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 these 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

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contracts, SCE recovers the costs incurred through demonstration of compliance with its CPUC-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 3,900 MW at September 30, 2012 and the amounts that SCE paid to these projects were $158 million and $178 million for the three months ended September 30, 2012 and 2011, respectively, and $292 million and $347 million for the nine months ended September 30, 2012 and 2011, respectively. These amounts are recoverable in customer rates, subject to reasonableness review.

Unconsolidated Trust

In May 2012, SCE Trust I issued $475 million (aggregate liquidation preference) of 5.625% trust securities (cumulative, liquidation amount of $25 per share) to the public and $10,000 of common stock (100%) to SCE. The trust invested the proceeds of these trust securities in Series F Preference Stock issued by SCE in the principal amount of $475 million (cumulative, $2,500 per share liquidation value) and which have substantially the same payment terms as the trust securities. The trust securities and the Series F Preference Stock do not have a maturity date. Upon any redemption of the Series F Preference Stock, a corresponding dollar amount of trust securities will be redeemed (for further information see Note 13). SCE Trust I will pay dividends at the same rate and on the same dates on the trust securities when, and if the SCE board of directors declare and make dividend payments on the Series F Preference Stock. The trust will use the dividends, if any, it receives on the Series F Preference Stock to make its corresponding dividend payments on the trust securities. If SCE does not make dividend payments to the trust, SCE would be prohibited from paying dividends on its common stock. SCE has fully and unconditionally guaranteed the payment of the trust securities and also its dividend payments, if and when, SCE pays dividends on the Series F Preference Stock.

SCE Trust I was formed for the exclusive purpose of issuing trust preference securities (“trust securities”). The trust is a VIE. SCE has concluded that it is not the primary beneficiary of this VIE as it does not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the trust. The trust's balance sheet as of September 30, 2012, consisted of an investment of $475 million in the Series F Preference Stock, $475 million of trust securities and $10,000 of common stock. The trust's income statement consisted of dividend income and accrued dividend payments of $7 million and $10 million for the three- and nine-months ended September 30, 2012, respectively.

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 considers assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk which was not material as of September 30, 2012 and December 31, 2011.

Assets and liabilities are categorized into a three-level 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:

	September 30, 2012
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	933	$	—	$	—		$	—		$	933
Derivative contracts:
Electricity	—		85		148			(44		)	189
Natural gas	1		—		—			(1		)	—
Fuel Oil	2		—		—			(2		)	—
Tolling	—		—		4			—			4
Subtotal of derivative contracts	3		85		152			(47		)	193
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks3	2,227		—		—			—			2,227
Municipal bonds	—		654		—			—			654
U.S. government and agency securities	467		122		—			—			589
Corporate bonds4	—		374		—			—			374
Short-term investments, primarily cash equivalents5	—		145		—			—			145
Subtotal of nuclear decommissioning trusts	2,694		1,295		—			—			3,989
Total assets6	3,638		1,380		152			(47		)	5,123
Liabilities at Fair Value
Derivative contracts:
Electricity	—		8		17			(15		)	10
Natural gas	1		115		6			(48		)	74
Tolling	—		—		617			—			617
Subtotal of derivative contracts	1		123		640			(63		)	701
Interest rate contracts	—		125		—			—			125
Total liabilities	1		248		640			(63		)	826
Net assets (liabilities)	$	3,637	$	1,132	$	(488	)	$	16		$	4,297

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	December 31, 2011
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	1,293	$	—	$	—		$	—		$	1,293
Derivative contracts:
Electricity	—		65		218			(58		)	225
Natural gas	4		5		—			(7		)	2
Fuel oil	4		—		—			(4		)	—
Tolling	—		—		10			—			10
Subtotal of derivative contracts	8		70		228			(69		)	237
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks3	1,899		—		—			—			1,899
Municipal bonds	—		756		—			—			756
U.S. government and agency securities	433		147		—			—			580
Corporate bonds4	—		317		—			—			317
Short-term investments, primarily cash equivalents5	—		15		—			—			15
Subtotal of nuclear decommissioning trusts	2,332		1,235		—			—			3,567
Total assets6	3,641		1,305		228			(69		)	5,105
Liabilities at Fair Value
Derivative contracts:
Electricity	—		10		77			(17		)	70
Natural gas	—		234		23			(52		)	205
Tolling	—		—		451			—			451
Subtotal of derivative contracts	—		244		551			(69		)	726
Interest rate contracts	—		90		—			—			90
Total liabilities	—		334		551			(69		)	816
Net assets (liabilities)	$	3,641	$	971	$	(323	)	$	—		$	4,289

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 and cash equivalents on Edison International's consolidated balance sheets.

³  Approximately 67% and 70% of the equity investments were located in the United States at September 30, 2012 and December 31, 2011, respectively.

⁴  At September 30, 2012 and December 31, 2011, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $42 million and $22 million, respectively.

⁵  Excludes net receivables of $8 million and $25 million at September 30, 2012 and December 31, 2011, respectively, of interest and dividend receivables as well as receivables and payables related to pending securities sales and purchases.

⁶  Excludes other investments of $70 million and $81 million at September 30, 2012 and December 31, 2011, respectively, primarily related to the cash surrender value of company owned life insurance investments which are used to fund certain executive benefits including deferred compensation. Also excludes other investments of $77 million and $118 million at September 30, 2012 and December 31, 2011, respectively, primarily related to leveraged leases.

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

	Three months ended September 30,								Nine months ended September 30,
(in millions)	2012				2011				2012				2011
Fair value of net assets (liabilities) at beginning of period	$	(343	)		$	(275	)		$	(323	)		$	97
Total realized/unrealized gains (losses):
Included in earnings1	12				(4		)		20				14
Included in regulatory assets and liabilities2	(124		)	3	162			3	(140		)	3	(220		)	3
Included in accumulated other comprehensive income4	(1		)		1				1				(2		)
Purchases	41				24				111				51
Settlements	(73		)		(8		)		(106		)		(38		)
Transfers into Level 3	—				—				—				—
Transfers out of Level 35	—				—				(51		)		(2		)
Fair value of net liabilities at end of period	$	(488	)		$	(100	)		$	(488	)		$	(100	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period6	$	(173	)		$	(110	)		$	(181	)		$	(425	)

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  Included in reclassification adjustments in Edison International's consolidated statements of other comprehensive income.

⁵  Transfers out of Level 3 into Level 2 occurred due to significant observable inputs becoming available as the transactions near maturity.

⁶  Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income was a loss of $7 million for three months ended September 30, 2012, and a gain of $7 million for the nine months ended September 30, 2011. The remainder of the unrealized losses relate to SCE. See 2 above.

The fair value for transfers in and transfers out of each level is determined at the end of each reporting period. There were no transfers between Levels 1 and 2 during the three- and nine-month periods ended September 30, 2012 and 2011.

Valuation Techniques Used to Determine Fair Value

Level 1

The fair value of Level 1 assets and liabilities is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. This level includes exchange-traded equity securities and derivatives, U.S. treasury securities and money market funds.

Level 2

The fair value of Level 2 assets and liabilities is determined using the income approach by obtaining quoted prices for similar assets and liabilities in active markets and inputs that are observable, either directly or indirectly, for substantially the full term of the instrument. This level includes fixed income securities, over-the-counter derivatives and interest rate swaps. For further discussion on fixed income securities, see "—Nuclear Decommissioning Trusts" below.

Over-the-counter derivative contracts are valued using standard pricing models to determine the net present value of estimated future cash flows. 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 price source that best represents trade activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes, prices from exchanges or comparison to executed trades are used to validate and corroborate the primary price 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.

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Level 3

The fair value of Level 3 assets and liabilities is determined using the income approach through various models and techniques that require significant unobservable inputs. This level includes over-the-counter options, tolling arrangements and derivative contracts that trade infrequently such as congestion revenue rights ("CRRs") and long-term power agreements.

Assumptions are made in order to value derivative contracts in which observable inputs are not available. Changes in fair value are based on changes to forward market prices, including extrapolation of short-term observable inputs into forecasted prices for illiquid forward periods. In circumstances where fair value cannot be verified with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. Modeling methodologies, inputs and techniques are reviewed and assessed as markets continue to develop and more pricing information becomes available and the fair value is adjusted when it is concluded that a change in inputs or techniques would result in a new valuation that better reflects the fair value of those derivative contracts.

Level 3 Valuation Process

The process of determining fair value is the responsibility of Edison International's subsidiaries' risk management, departments, which report to their respective chief financial officer. These departments obtain observable and unobservable inputs through broker quotes, exchanges and internal valuation techniques that use both standard and proprietary models to determine fair value. Each reporting period, the risk and finance departments collaborate to determine the appropriate fair value methodologies and classifications for each derivative. Inputs are validated for reasonableness by comparison against prior prices, other broker quotes and volatility fluctuation thresholds. Inputs used and valuations are reviewed period-over-period and compared with market conditions to determine reasonableness.

The following table sets forth the valuation techniques and significant unobservable inputs used to determine fair value for Level 3 assets and liabilities at September 30, 2012:

	Fair Value (in millions)							Significant	Range
	Assets			Liabilities			Valuation Technique(s)	Unobservable Input	(Weighted Average)
Electricity:
Options	$	23		$	26		Option model	Volatility of gas prices	23% - 41% (31%)
								Volatility of power prices	28% - 60% (39%)
								Power prices	$38.10 - $58.80 ($45.30)
Forwards	15			20			Discounted cash flow	Power prices	$18.25 - $64.50 ($34.57)
Congestion contracts	100			—			Market simulation model	Load forecast	7,597 MW - 26,612 MW
								Power prices	$(13.90) - $226.75
								Gas prices	$2.95 - $7.78
Congestion contracts	62			24			Latest auction pricing	Congestion prices	$(5.39) - $11.87 ($0.13)
Gas options	—			6			Option model	Volatility of gas prices	24% - 41% (35%)
Tolling	5			617			Option model	Volatility of gas prices	17% - 41% (21%)
								Volatility of power prices	26% - 60% (28%)
								Power prices	$33.20 - $100.80 ($56.10)
Netting	(53		)	(53		)
Total derivative contracts	$	152		$	640

Level 3 Fair Value Sensitivity

Gas Options, Electricity Options, and Tolling Arrangements

The fair values of option contracts and tolling arrangements contain intrinsic value and time value. Intrinsic value is the difference between the market price and strike price of the underlying commodity. Time value is made up of several components, including volatility, time to expiration, and interest rates. The fair value of option contracts changes as the underlying commodity price moves away or towards the strike price. The option model for tolling arrangements reflects plant specific information such as operating and start-up costs.

For tolling arrangements and certain gas and power option contracts where Edison International subsidiaries are the buyer, increases in volatility of the underlying commodity prices would result in increases to fair value as it represents greater price

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movement risk. As power and gas prices increase, the fair value of the option contracts and tolling arrangements tends to increase. The valuation of power option contracts and tolling arrangements is also impacted by the correlation between gas and power prices. As the correlation increases, the fair value of power option contracts and tolling arrangements tends to decline.

Forward Power Contracts

Generally, an increase (decrease) in long-term forward power prices at illiquid locations where Edison International subsidiaries are the seller relative to the contract price will decrease (increase) fair value. Inversely as a buyer, an increase (decrease) in long-term forward power prices at illiquid locations relative to the contract price will increase (decrease) fair value.

Congestion Contracts

When valuation is based on a discounted cash flow model and Edison International subsidiaries are the buyer, generally an increase (decrease) in congestion prices in the last auction relative to the contract price will increase (decrease) fair value.

When valuation is based on a market simulation model and Edison International subsidiaries are the buyer, generally increases (decreases) in forecasted load would result in increases (decreases) to fair value. In general, increases (decreases) in electricity and gas prices at illiquid locations tends to result in increases (decreases) to fair value; however, changes in electricity and gas prices in opposite directions may have varying results on fair value.

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, 2012				December 31, 2011
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current portion	$	14,273	$	14,452	$	13,746	$	14,264

Fair value of short-term and long-term debt is classified as Level 2 and 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 of new issue prices and relevant credit information.

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

Note 5.    Debt and Credit Agreements

Project Financings

Broken Bow and Crofton Bluffs

Effective March 30, 2012, EME, through its subsidiaries, Broken Bow Wind, LLC and Crofton Bluffs Wind, LLC, completed two nonrecourse financings of its interests in the Broken Bow and Crofton Bluffs wind projects. The financings included construction loans totaling $79 million that are required to be converted to 15-year amortizing term loans by March 31, 2013, subject to meeting specified conditions, $13 million letter of credit facilities and $6 million working capital facilities. Interest under the construction and term loans will accrue at London Interbank Offered Rate (LIBOR) plus 2.875%, with the term loan rate increasing 0.125% after the third, sixth, ninth, and twelfth years. As of September 30, 2012, $21 million and $6 million were outstanding under the construction loans included in short-term debt on EME's consolidated balance sheet, and letters of credit facilities, respectively.

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Tapestry Wind

In December 2011, EME through its subsidiary, Tapestry Wind, LLC, completed a nonrecourse financing of its interests in the Taloga, Buffalo Bear and Pinnacle wind projects. A total of $97 million of cash proceeds received from the $214 million10-year partially amortizing term loan was deposited into an escrow account as of December 31, 2011. On February 22, 2012, a neighbor of the Pinnacle project, filed a formal complaint with the West Virginia Public Service Commission regarding, among other things, noise emissions and shadow flicker and requested that the Commission order the project to shut down at night due to alleged noise emissions. This complaint was dismissed on June 1, 2012. On June 27, 2012 and on July 3, 2012, nearly identical complaints were filed with the West Virginia Public Service Commission by two other neighbors and were subsequently dismissed. In addition, on June 25, 2012, each of the three neighbors filed separate civil complaints in the Circuit Court of Mineral County, West Virginia against Pinnacle Wind, LLC, EME, Edison Mission Operations and Maintenance, Inc., and other non-affiliated defendants. The civil complaints allege, among other things, that the noise emissions and shadow flicker from the Pinnacle wind farm constitute a nuisance and seek compensatory damages, punitive damages and other equitable relief. The complaints have been dismissed without prejudice. The release of the loan proceeds in escrow is subject to final resolution of the complaints or further due diligence from the lenders.

Big Sky Turbine Financing

In October 2009, EME, through its subsidiary, Big Sky Wind, LLC (Big Sky), entered into turbine financing arrangements with the turbine manufacturer, totaling approximately $206 million for wind turbine purchase obligations related to the 240 MW Big Sky wind project. The loan has a five-year final maturity, however, specific events, including project performance, may trigger earlier repayment which could occur as early as February 2013. Big Sky is currently involved in a dispute with the lender/turbine manufacturer around whether certain latent defects existing in the turbine equipment would preclude the early repayment provisions. The loan is secured by a leasehold mortgage on the project's real property assets, a pledge of all other collateral of the Big Sky wind project, as well as a cash reserve account into which one-third of distributable cash flow, if any, of the Big Sky wind project is to be deposited on a monthly basis. The loan is also secured by pledges of Big Sky's direct and indirect ownership interests in the project but is non-recourse to EME.

Big Sky will need to arrange alternative financing, if available, to repay the loan at maturity or reach agreement with the lender to extend the maturity date of the loan as EME does not plan to make an investment in the project and is under no obligation to do so. If these efforts are unsuccessful, the lender may foreclose on the project resulting in a write off of the entire investment in the project. At September 30, 2012, EME's net investment in the Big Sky wind project was $130 million.

Long-Term Debt

In March 2012, SCE issued $400 million of 4.05% first and refunding mortgage bonds due in 2042. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.

Credit Agreements and Short-Term Debt

During the second quarter of 2012, SCE replaced its credit facilities with a $2.75 billion five-year revolving credit facility that matures in May 2017. The credit facility is generally used to support commercial paper and letters of credit issued for procurement-related collateral requirements, balancing account undercollections and for general corporate purposes, including working capital requirements to support operations and capital expenditures. At September 30, 2012, SCE's outstanding commercial paper supported by the credit facility was $380 million at a weighted-average interest rate of 0.43%. At September 30, 2012, letters of credit issued under SCE's credit facility aggregated $196 million and are scheduled to expire in twelve months or less. At December 31, 2011, the outstanding commercial paper was $419 million at a weighted-average interest rate of 0.44%.

In February 2012, EME terminated its $564 million revolving credit facility. Midwest Generation's $500 million credit facility expired in June 2012 as per its terms. In the first quarter of 2012, EME completed a $100 million letter of credit facility for EME's general corporate needs and for its projects, which expires on June 30, 2014. Letters of credit issued under this facility are secured by cash collateral at least equal to the issued amount.

During the second quarter of 2012, Edison International (parent) replaced its credit facility with a $1.25 billion five-year revolving credit facility that matures in May 2017. Borrowings under this credit facility are used for general corporate purposes. At September 30, 2012, Edison International (parent) outstanding short-term debt supported by this credit facility was $28 million at a weighted-average interest rate of 1.52%. At December 31, 2011, the outstanding short-term debt was $10 million at a weighted-average interest rate of 0.66%.

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Letters of Credit

At September 30, 2012, letters of credit under EME's and its subsidiaries' credit facilities aggregated $154 million. EME had $51 million of cash collateral supporting its letters of credit which were scheduled to expire as follows: $48 million in 2013 and $3 million in 2014. In addition, EME's subsidiaries' credit facilities aggregated $103 million and were scheduled to expire as follows: $2 million in 2012, $49 million in 2013, $21 million in 2017, $18 million in 2018 and $13 million in 2021. Standby letters of credit include $30 million issued in connection with the power purchase agreement with SCE under the Walnut Creek credit facility. Certain letters of credit are subject to automatic annual renewal provisions.

Note 6.    Derivative Instruments and Hedging Activities

Electric Utility

Commodity Price Risk

SCE is exposed to commodity price risk which represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's hedging program reduces customer 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 approved by the 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 energy purchased from and sold to wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities and power purchase agreements.

SCE's natural gas price exposure arises from natural gas purchased for 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, 2012	December 31, 2011
Electricity options, swaps and forwards	GWh	18,304	30,881
Natural gas options, swaps and forwards	Bcf	142	300
Congestion revenue rights	GWh	140,263	166,163
Tolling arrangements	GWh	102,123	104,154

Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at September 30, 2012:

	Derivative Assets									Derivative Liabilities1
(in millions)	Short-Term			Long-Term			Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	55		$	80		$	135		$	177		$	1,002		$	1,179		$	1,044
Netting and collateral	(18		)	(6		)	(24		)	(49		)	(19		)	(68		)	(44		)
Total	$	37		$	74		$	111		$	128		$	983		$	1,111		$	1,000

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.

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

	Derivative Assets									Derivative Liabilities
(in millions)	Short-Term			Long-Term			Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	86		$	85		$	171		$	303		$	856		$	1,159		$	988
Netting and collateral	(21		)	(15		)	(36		)	(37		)	(51		)	(88		)	(52		)
Total	$	65		$	70		$	135		$	266		$	805		$	1,071		$	936

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 purchase power costs recovered from customers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from customers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.

The following table summarizes the components of economic hedging activity:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Realized gains (losses)	$	(77	)	$	(58	)	$	(199	)	$	(132	)
Unrealized gains (losses)	(91		)	(110		)	(29		)	(433		)

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 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 $113 million and $216 million as of September 30, 2012 and December 31, 2011, respectively, for which SCE has posted no collateral to its counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2012, SCE would be required to post $25 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. Substantially all of the contracts that SCE has executed with counterparties are either entered into under SCE's procurement plan which has been pre-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.

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Competitive Power Generation

EMG's subsidiary, EME uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, transmission rights and 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 EME does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements.

Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not designated as cash flow hedges. Economic hedges are accounted for at fair value on the consolidated balance sheets as derivative assets or liabilities with offsetting changes recorded on the consolidated statements of operations. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized on the consolidated balance sheets as derivative assets or liabilities with offsetting changes in fair value, to the extent effective, recognized in accumulated other comprehensive loss until reclassified into earnings when the related forecasted transaction occurs. The portion of a cash flow hedge that does not offset the change in the fair value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings.

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, with offsetting changes recognized in operating revenues on the consolidated statements of operations.

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

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

Notional Volumes of Derivative Instruments

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

September 30, 2012
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges	Economic Hedges		Trading Activities
Electricity	Forwards/Futures	Sales, net	GWh	5,644	58	2	—
Electricity	Forwards/Futures	Purchases, net	GWh	—	—		550
Electricity	Capacity	Purchases, net	GW-Day	—	—		97	1
Electricity	Congestion	Purchases, net	GWh	—	241	3	281,251	3
Natural gas	Forwards/Futures	Sales, net	bcf	—	—		0.4
Fuel oil	Forwards/Futures	Sales, net	barrels	—	—		100,000
Fuel oil	Forwards/Futures	Purchases, net	barrels	—	120,000		—

At September 30, 2012, EME had interest rate contracts with notional values totaling $727 million that converted floating rate LIBOR-based debt to fixed rates ranging from 0.79% to 4.29%. These contracts expire May 2013 through March 2026. In addition, at September 30, 2012, EME had forward starting interest rate contracts with notional values totaling $641 million that will convert floating rate LIBOR-based debt to fixed rates ranging from 0.7825% to 4.0025%. These contracts have effective dates beginning December 2012 through December 2021 and expire December 2013 through December 2029.

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December 31, 2011
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges		Economic Hedges		Trading Activities
Electricity	Forwards/Futures	Sales, net	GWh	8,320		335	2	—
Electricity	Forwards/Futures	Purchases, net	GWh	—		—		2,926
Electricity	Capacity	Sales, net	GW-Day	61	1	—		—
Electricity	Capacity	Purchases, net	GW-Day	—		—		184	1
Electricity	Congestion	Purchases, net	GWh	—		1,261	3	230,798	3
Natural gas	Forwards/Futures	Sales, net	bcf	—		—		0.2
Fuel oil	Forwards/Futures	Purchases, net	barrels	—		240,000		—

¹  EME's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM Interconnection, LLC Reliability Pricing Model (PJM RPM) auction is not accounted for as a derivative.

²  These positions adjust financial and physical positions, or day-ahead and real-time positions, to reduce costs or increase gross margin. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.

³  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.

At December 31, 2011, EME had interest rate contracts with notional values totaling $644 million that converted floating rate LIBOR-based debt to fixed rates ranging from 0.79% to 4.29%. These contracts expire May 2013 through March 2026. In addition, EME had forward starting interest rate contracts with notional values totaling $506 million that will convert floating rate LIBOR-based debt to fixed rates of 3.5429%, 3.57% and 4.0025%. These contracts have effective dates of June 2013 and December 2021 and expire May 2023 and December 2029.

Fair Value of Derivative Instruments

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

September 30, 2012
	Derivative Assets									Derivative Liabilities
(in millions)	Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal			Net Assets (Liabilities)
Non-trading activities
Cash flow hedges
Commodity contracts	$	14		$	2		$	16		$	9		$	1		$	10		$	6
Interest rate contracts	—			—			—			—			125			125			(125		)
Economic hedges	25			1			26			23			1			24			2
Trading activities	321			145			466			265			98			363			103
	360			148			508			297			225			522			(14		)
Netting and collateral received1	(321		)	(105		)	(426		)	(296		)	(100		)	(396		)	(30		)
Total	$	39		$	43		$	82		$	1		$	125		$	126		$	(44	)

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December 31, 2011
	Derivative Assets									Derivative Liabilities
(in millions)	Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal			Net Assets (Liabilities)
Non-trading activities
Cash flow hedges
Commodity contracts	$	40		$	1		$	41		$	2		$	—		$	2		$	39
Interest rate contracts	—			—			—			—			90			90			(90		)
Economic hedges	24			—			24			20			—			20			4
Trading activities	277			142			419			232			79			311			108
	341			143			484			254			169			423			61
Netting and collateral received1	(301		)	(81		)	(382		)	(253		)	(79		)	(332		)	(50		)
Total	$	40		$	62		$	102		$	1		$	90		$	91		$	11

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,
	2012						2011
(in millions)	Commodity Contracts			Interest Rate Contracts			Commodity Contracts			Interest Rate Contracts			Income Statement Location
Beginning of period derivative gains (losses)	$	35		$	(90	)	$	43		$	(16	)
Effective portion of changes in fair value	3			(35		)	2			(64		)
Reclassification to earnings	(31		)	—			(29		)	—			Competitive power generation revenue
End of period derivative gains (losses)	$	7		$	(125	)	$	16		$	(80	)

¹  Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive loss at September 30, 2012 and 2011 for commodity and interest rate contracts were $7 million and $(79) million, and $10 million and $(49) million, respectively.

For additional information, see Note 11.

EME recorded gains (losses) of $(2) million and $2 million during the three months ended September 30, 2012 and 2011, respectively, and gains of none and $2 million during the nine months ended September 30, 2012 and 2011, respectively, in operating revenues on the consolidated statements of income representing the amount of cash flow hedge ineffectiveness.

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

		Three months ended September 30,					Nine months ended September 30,
(in millions)	Income Statement Location	2012		2011			2012		2011
Economic hedges	Competitive power generation revenues	$	8	$	(3	)	$	25	$	5
	Fuel	3		(3		)	2		1
Trading activities	Competitive power generation revenues	22		11			72		68

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Contingent Features

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's and its subsidiaries' credit ratings are below investment grade, EME and its subsidiaries have provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties.

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, 2012		December 31, 2011
Collateral provided to counterparties:
Offset against derivative liabilities	$	54	$	53
Reflected in margin and collateral deposits	88		58
Collateral received from counterparties:
Offset against derivative assets	39		53

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.

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Income from continuing operations before income taxes	$	477		$	658		$	781		$	1,218
Provision for income tax at federal statutory rate of 35%	167			230			273			426
Increase (decrease) in income tax from:
State tax – net of federal benefit	60			28			56			40
Production and housing credits	(12		)	(12		)	(48		)	(48		)
Property-related	(20		)	(18		)	(39		)	(38		)
Other	(14		)	4			(25		)	(10		)
Total income tax expense from continuing operations	$	181		$	232		$	217		$	370
Effective tax rate	38		%	35		%	28		%	30		%

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.

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Accounting for Uncertainty in Income Taxes

The following table provides a reconciliation of unrecognized tax benefits:

(in millions)	2012			2011
Balance at January 1,	$	631		$	565
Tax positions taken during the current year:
Increases	22			53
Tax positions taken during a prior year:
Increases	207			60
Decreases	(29		)	(37		)
Decreases for settlements during the period	—			—
Balance at September 30,	$	831		$	641

As of September 30, 2012 and December 30, 2011, respectively, if recognized, $578 million and $532 million of the unrecognized tax benefits would impact the effective tax rate.

Tax Dispute

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 EME's international assets, which if sustained, would result in a federal tax payment of approximately $198 million, including interest and penalties through September 30, 2012 (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 $95 million, including interest through September 30, 2012.

Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011. The appeals process to date has not resulted in a change in the proposed adjustment by the IRS on the taxable gain on the 2004 sale of EME's international assets. If a deficiency notice is issued on this item, it would require payment of the tax, interest and any penalties within 90 days of its issuance or a filing of a petition in United States Tax Court.

Tax Election at Homer City

On March 15, 2012, Homer City made an election to be treated as a partnership for federal and state income tax purposes. As a result of this election, Homer City is treated for tax purposes as distributing its assets and liabilities to its partners, both of which are wholly owned subsidiaries of EME, and triggering tax deductions of approximately $1.0 billion. Such tax deductions were included in Edison International's 2011 consolidated tax returns.

Loss and Credit Carryforwards

Including the tax deduction generated from the Homer City election, Edison International has recorded tax benefits for federal and state net operating loss carryforwards and federal tax credit carryforwards of approximately $1.6 billion as of September 30, 2012.

Repair Deductions

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. In August 2011, the IRS issued guidance on repair deductions and changes in accounting method related to transmission and distribution assets. Based on this guidance, SCE included a second change in tax accounting method on repair costs in its 2011 tax return. Guidance for generation assets is pending. Regulatory treatment for the incremental deductions taken after the voluntary election to change SCE's tax accounting method for certain repair costs is part of SCE's 2012 GRC. Due to the pending regulatory decision, SCE has not recognized an earnings benefit or regulatory asset related to this method change and incremental deductions taken in 2009, 2010 and 2011. In October 2012, the CPUC assigned administrative law judge issued a proposed GRC decision, which if adopted, would result in an earnings

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benefit of approximately $230 million attributable to flow through treatment of 2009 – 2011 vintage year activity. SCE would also record an earnings benefit related to 2012 vintage year activity consistent with the rate making treatment.

Note 8.    Compensation and Benefit Plans

Pension Plans

As part of the pension funding provisions contained in the Surface Transportation Extension Act of 2012 passed by Congress, Edison International's projected 2012 plan contributions have been reduced to $180 million from $286 million, which resulted in a third quarter regulatory adjustment reflected in the table below. Contributions of $156 million were made during the nine months ended September 30, 2012. The 2012 GRC proposed decision authorized contributions of $168 million with recovery of any undercollection through the continuation of the existing balancing account mechanism. A final GRC decision is expected by year-end. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.

Expense components are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Service cost	$	49		$	43		$	135		$	129
Interest cost	49			52			147			156
Expected return on plan assets	(56		)	(60		)	(174		)	(180		)
Amortization of prior service cost	1			2			3			6
Amortization of net loss	21			6			57			18
Expense under accounting standards	64			43			168			129
Regulatory adjustment (deferred)	(57		)	(6		)	(3		)	(18		)
Total expense recognized	$	7		$	37		$	165		$	111

Postretirement Benefits Other Than Pensions

Edison International made contributions of $17 million during the nine months ended September 30, 2012 and expects to make $48 million of additional contributions during the remainder of 2012. In 2012, annual contributions made to plans for SCE employees are expected to be recovered through CPUC-approved regulatory mechanisms. Annual contributions are expected to be, at a minimum, equal to the total annual expense for these plans. Benefits under these plans, with some exceptions, are generally unvested and subject to change.

Expense components are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Service cost	$	13		$	11		$	39		$	33
Interest cost	30			33			90			99
Expected return on plan assets	(27		)	(28		)	(81		)	(84		)
Special termination benefits1	3			—			3			—
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss	12			9			36			27
Total expense	$	22		$	16		$	60		$	48

¹  Due to the reduction in the workforce at San Onofre, Edison International has incurred costs for enhanced retiree health care coverage. See below for further information.

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San Onofre Workforce Reduction

In August 2012, SCE announced plans for downsizing to bring the San Onofre organization and cost structure in line with industry peers. SCE plans to reduce the San Onofre workforce by 730 employees to 1,500 employees beginning in the fourth quarter of 2012 and continuing in 2013. At September 30, 2012, SCE had recorded $30 million in estimated cash severance costs (SCE's share) related to the non-represented employee workforce reduction.

Note 9.    Commitments and Contingencies

Third-Party Power Purchase Agreements

During the nine months ended September 30, 2012, SCE had power purchase contracts with additional commitments estimated to be: $17 million in 2014, $43 million in 2015, $66 million in 2016 and $970 million for the period remaining thereafter. Some of these power purchase agreements are classified as operating leases. The additional commitments for these leases, which are also included in the amounts above, are estimated to be: $21 million in 2015, $45 million in 2016 and $942 million for the period remaining thereafter.

Coal Transportation Agreements

At September 30, 2012, Midwest Generation had contractual agreements for the transportation of coal. The commitments under these contracts are based on either actual coal purchases derived from committed coal volumes set forth in fuel supply contracts or minimum quantities as set forth in the transportation agreements as adjusted for provisions that mitigate the financial exposure of Midwest Generation related to a plant closure under certain circumstances as specified in the agreements. Estimated contractual obligations for coal transportation agreements are estimated to aggregate $2.3 billion, which consists of: $118 million for the remainder of 2012, $292 million for 2013, $286 million for 2014, $260 million for 2015, $260 million for 2016 and $1.1 billion thereafter. Years subsequent to 2012 reflect a reduction in minimum volumes for the shutdown of the Fisk and Crawford Stations.

Capital Commitments

At September 30, 2012, EMG's subsidiaries had firm commitments to spend approximately $92 million during the remainder of 2012, $44 million for 2013 and $17 million for 2015 for capital expenditures. These expenditures primarily relate to the Walnut Creek project, construction of wind projects and capital expenditures at the Midwest Generation plants.

Homer City Lease

Homer City received a forbearance of the $47 million senior rent payment due October 1, 2012. Homer City made the required April 1, 2012 senior rent payment of $48 million but did not make the April 1, 2012 payment of equity rent of $65 million and was granted a waiver by the owner-lessors of any rent default event with respect to the payment of the equity rent for all purposes other than restrictions on distributions from Homer City, including repayment of its intercompany loan, and the $48 million senior rent reserve letter of credit remains in place. Homer City and an affiliate of GECC entered into the Homer City MTA for the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities. For further discussion, see Note 18.

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 owner-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," and one of the Powerton-Joliet owner-lessors has made a similar request for indemnification. Commonwealth Edison has also advised EME

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that it believes it is entitled to indemnification for costs and expenses incurred in connection with the information requested under the Comprehensive Environmental Response, Compensation and Liability Act of 1980 regarding environmental sampling and investigation performed at Midwest Generation's Fisk and Crawford sites. 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, the supplemental agreement has been extended until February 2013. There were approximately 230 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at September 30, 2012. Midwest Generation had recorded a liability of $53 million at September 30, 2012 related to this contractual indemnity.

Indemnities Related to the Homer City Plant

In connection with the original 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 owner-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, 2012, EME had recorded a liability of $20 million related to these matters.

In connection with the sale-leaseback transactions related to the Homer City plant in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Under certain of these tax indemnity agreements, Homer City and Midwest Generation, as the lessees in the sale-leaseback transactions agreed to indemnify the respective owner-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 range of estimated obligations which would be triggered by a valid claim from the owner-lessors. EME has not recorded a liability for these matters.

In addition to the indemnity provided by Homer City, EME agreed to indemnify the owner-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 owner-lessor's debt is characterized as recourse, rather than nonrecourse. This indemnity covers a limited range of possible tax consequences that are unrelated to performance under the lease.

Upon closing of the Homer City MTA, the tax indemnity agreements between EME, Homer City and GECC will be terminated and GECC will release EME and Homer City from its obligations thereunder. Completion of the Homer City MTA is subject to the satisfaction of a number of closing conditions, including the successful restructuring and reorganization of an affiliate of GECC and receipt of the regulatory approvals required for the transfer of the Homer City plant to GECC. For further discussion, see Note 18.

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Indemnity Provided as Part of the Acquisition of Mountainview

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

Mountainview Filter Cake Indemnity

SCE has indemnified the City of Redlands, California in connection with Mountainview's California Energy Commission permit 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 and Guarantees

EME guarantees Midwest Generation's payments under the Powerton and Joliet sale-leaseback agreements. A default by Midwest Generation in meeting its obligations under those agreements could have an adverse impact on EME.

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, individually or in the aggregate, 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 called for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at all units subject to the complaint and other remedies. 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 intervened in the case.

Nine of the ten PSD claims raised in the complaint 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, and 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. The dismissals have been certified as "partial final judgments" capable of appeal, and an appeal is pending before the Seventh Circuit Court of Appeals. The remaining claims have been stayed pending the appeal. In February 2012, certain of the environmental action groups that had intervened in the case entered into an agreement with Midwest Generation to dismiss without prejudice all of their opacity claims as to all defendants. The agreed upon motion to dismiss was approved by the court on March 26, 2012.

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In January 2012, two complaints were filed against Midwest Generation in Illinois state court by residents living near the Crawford and Fisk Stations on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs seek to have their suits certified as a class action and request injunctive relief, as well as compensatory and punitive damages. The complaints are similar to two complaints previously filed in the Northern District of Illinois, which were dismissed in October 2011 for lack of federal jurisdiction. Midwest Generation's motions to dismiss the cases were denied in August 2012, following which the plaintiffs filed amended complaints alleging substantially similar claims and requesting similar relief.

In October 2012, Midwest Generation and the Illinois Environmental Protection Agency entered into Compliance Commitment Agreements outlining specified environmental remediation measures and groundwater monitoring activities to be undertaken at its Powerton, Joliet, Crawford, Will County and Waukegan generating stations. Also in October 2012, several environmental groups filed a complaint before the Illinois Pollution Control Board against Midwest Generation, alleging violations of the Illinois groundwater standards through the operation of coal ash disposal ponds at its Powerton, Joliet, Waukegan and Will County generating stations. The complaint requests the imposition of civil penalties, injunctive relief and remediation.

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 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. EME has not recorded a liability for these matters.

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 PADEP, the State of New York and the State of New Jersey intervened in the lawsuit. In October 2011, all of the claims in the US EPA's lawsuit were dismissed with prejudice. An appeal of the dismissal is pending before the Third Circuit Court of Appeals.

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. In October 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 plaintiffs will file a complaint in state court.

In February 2012, Homer City received a 60-day Notice of Intent to Sue indicating the Sierra Club’s intent to file a citizen lawsuit alleging violations of emissions standards and limitations under the CAA and the Pennsylvania Air Pollution Control Act.

Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material impact on the financial condition and results of operations of Homer City and EME. EME cannot predict the outcome of these matters or estimate the impact on the Homer City plant, or its and Homer City's results of operations, financial position or cash flows. EME has not recorded a liability for these matters.

San Onofre Outage, Inspection and Repair Issues

SCE replaced four steam generators at San Onofre Units 2 and 3 in 2010 and 2011, respectively. In the first quarter of 2012, a water leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. Unit 3 was safely taken off-line. At the time, San Onofre Unit 2 was off-line for a planned outage when areas of unexpected wear in some of its heat transfer tubes were found. Both Units have remained off-line for extensive inspections, testing and analysis of their steam generators. Each Unit will be restarted only when and if SCE determines that it is safe to do so and when start-up has been approved by the NRC pursuant to the terms of a Confirmatory Action Letter (“CAL”) issued by the NRC in March 2012. The CAL requires NRC permission to restart Unit 2 and Unit 3 and outlines actions SCE must complete before

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permission to restart either Unit may be sought. In October 2012, SCE submitted to the NRC a response to the CAL and restart plans for Unit 2. SCE proposed to restart Unit 2 and operate at a reduced power level (70%) for approximately five months, followed by a mid-cycle scheduled outage.

In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million after adjustment for inflation) for SCE's 78.21% share of San Onofre to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $594 million through September 30, 2012 on the steam generator replacement project, including $95 million reflected in construction work in progress primarily related to the disposal of the replaced steam generators. Those expenditures remain subject to CPUC reasonableness review. Final costs for the project will not be known until after disposal of the original steam generators is completed.

As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre are being purchased in the market by SCE (commencing on February 1 for Unit 3 and March 5 for Unit 2). Market costs through September 30, 2012 were approximately $221 million, net of avoided nuclear fuel costs, and are recoverable through the ERRA balancing account subject to CPUC reasonableness review. Because of the uncertainties associated with when and at what output levels the Units will or may be returned to service, total potential market power costs cannot be estimated at this time.

Through September 2012, SCE's share of incremental inspection and repair costs totaled $96 million for both Units. At September 30, 2012, the repairs to restart Unit 2 at the reduced power levels described above have been substantially completed. The costs for Unit 2 may increase following NRC review under the CAL and any new developments that may result from further analysis, testing and inspection, and there is no assurance that start-up of Unit 2 will occur as described above. Total incremental repair costs associated with returning Unit 3 to service, and returning both Units to service at originally specified capabilities safely, remain uncertain.

In addition to the amounts for inspection and repair and market power costs discussed below, SCE has collected through customer rates an estimated $625 million of revenue through third quarter 2012 (based on current authorized revenue requirements) associated with the plant. SCE's total 2012 San Onofre annual revenue requirement, including the 2012 GRC proposed decision, is approximately $820 million, made up of $170 million in refueling outage, nuclear fuel and decommissioning costs and $650 million for its direct operating and maintenance costs, depreciation and return on its investment in San Onofre Unit 2, Unit 3 and related common plant. At September 30, 2012, SCE's rate base and net investment and inventory associated with San Onofre was $1.2 billion and $2.1 billion, respectively.

Under California Public Utilities Code Section 455.5, SCE is required to notify the CPUC if either of the San Onofre Units has been out of service for nine consecutive months (not including preplanned outages). SCE will provide such notice to the CPUC on November 1, 2012 for Unit 3 and expects to do so by December 6, 2012 for Unit 2. The CPUC is required within 45 days of SCE's notice for a particular Unit to initiate an investigation to determine whether to remove from customer rates some or the entire revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such rates are collected subject to refund. Under Section 455.5 any determination to adjust rates is made after hearings are conducted in connection with the utility's next general rate case. If, after investigation and hearings, the costs associated with a Unit are disallowed recovery because it is out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation.

In October 2012, in advance of SCE's required notification under Section 455.5, the CPUC issued an order instituting investigation ("OII") that will consolidate all San Onofre issues in related regulatory proceedings and consider appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, market power costs, capital and operations and maintenance costs, and seismic study costs. The order requires that all San Onofre-related costs incurred on and after January 1, 2012 be tracked in a memorandum account and, to the extent included in rates, collected subject to refund. The order also states that the CPUC will determine whether to order the immediate removal, effective as of the date of the order, of all costs related to San Onofre from SCE's rates, with placement of those costs in a deferred debit account pending the return of one or both Units to useful service, or other possible action. SCE will file its response to the order by November 26, 2012. SCE must also file testimony by December 10, 2012 detailing proposed rate adjustments due to the outages, including the amount of San Onofre costs in current rates, the amount to be removed, if any, the effective date, and related information. A pre-hearing conference will be scheduled early in 2013 after the issuance of a Scoping Memo by the Assigned Commissioner.

In parallel with the order instituting investigation, the 2012 GRC proposed decision would, if adopted, require SCE to track San Onofre-related costs in a memorandum account subject to refund, beginning January 1, 2012. SCE would be required by January 30, 2013 to file an application for reasonableness review of these costs and the proposed decision would allow that application to be consolidated with other proceedings. The 2012 GRC proposed decision also approves expenditures incurred

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through 2011 for the high pressure turbine project, but disallows recovery for post-2011 expenditures associated with the project and directs SCE to record those costs in either the memorandum account or seek future rate recovery in the next GRC. SCE anticipates that the inter-relationship between the Section 455.5 process and the issues to be reviewed in the investigation or pursuant to a final decision in the GRC will be addressed by the CPUC as it continues to develop the scope of the issues to be consolidated within the investigation.

The steam generators were designed and supplied by MHI and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. SCE's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include "the cost of replacement power." Such limitations in the contract are subject to applicable exceptions. In September 2012, SCE submitted an invoice to MHI for costs paid through June 30, 2012 in the amount of $45 million for both SCE's and the other co-owners' share of steam generator repair costs. SCE expects to continue to invoice MHI for costs incurred. No amounts have been recognized in the financial statements as of September 30, 2012.

San Onofre carries both property damage and outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of potential claims for loss recovery. In October 2012, SCE filed separate proofs of loss for Unit 2 and Unit 3 under the outage policy. Pursuant to these proofs of loss SCE is seeking the weekly indemnity amounts provided under the policy for each Unit. Because the outage is ongoing, SCE will supplement these proofs of loss in the future. No amounts have been recognized in SCE's financial statements, pending further actions by NEIL. To the extent any costs are recovered under the outage policy, SCE expects to refund those amounts to ratepayers through the ERRA balancing account.

SCE will pursue recoveries arising from available agreements, but there is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements.

CPSD Investigations

San Gabriel Valley Windstorm Investigation

In November 2011, a windstorm resulted in significant damage to SCE’s electric system and service outages for SCE customers primarily in the San Gabriel Valley. The CPUC directed its Consumer Protection and Safety Division (“CPSD”) to conduct an investigation focused on the cause of the outages, SCE’s service restoration effort, and SCE’s customer communications during the outages. The CPSD issued its preliminary report on February 1, 2012. The report asserts that SCE and others with whom SCE shares utility poles violated certain CPUC safety rules applicable to overhead line construction, maintenance and operation, which may have caused the failures of affected poles and supporting cables. The report also concludes that SCE’s restoration time was not adequate and makes other assertions. Additionally, the report contends that SCE violated CPUC rules by failing to preserve evidence relevant to the investigation when it did not retain damaged poles that were replaced following the windstorm. If the CPUC issues an OII regarding this matter and SCE is found to have violated any CPUC rules, it could face penalties. SCE is unable to estimate a possible loss or range of loss associated with any penalties that may be imposed by the CPUC on SCE.

The proposed decision in SCE’s 2012 GRC would direct SCE to, among other things, make an assessment of a representative sampling of its loaded poles to determine their conformance with current legal standards and report by January 31, 2013 on the results of this assessment. The cost of any large scale review of poles or other equipment for safety compliance, as well as any remediation measures required to assure compliance, could be significant.

Malibu Fire Order Instituting Investigation

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 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. In September 2012, the CPUC approved a partial settlement between the CPSD and three telecomm providers, leaving SCE and a non-settling telecomm provider as the remaining respondents. The partial settlement did not resolve any of the claims against SCE or the remaining telecomm provider.

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Four Corners New Source Review Litigation

In October 2011, four private environmental organizations filed a CAA citizen 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” and the plant's failure to obtain permits and install best available control technology ("BACT") violated the PSD requirements and the New Source Performance Standards of the CAA. The complaint also alleges subsequent and continuing violations 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 certain closing conditions, including APS obtaining a long-term fuel supply agreement for the plant, and is expected to close no earlier than December 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 is unable to estimate a possible loss or range of loss associated with this matter.

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, operation 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.

At September 30, 2012, Edison International's recorded estimated minimum liability to remediate its 27 identified material sites (sites in which the upper end of the range of the costs is at least $1 million) at SCE (25 sites) and EME (2 sites related to Midwest Generation) was $121 million, of which $113 million was related to SCE, including $78 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. Of the $116 million total environmental remediation liability for SCE, $113 million has been recorded as a regulatory asset. SCE expects to recover $31 million through an incentive mechanism that allows SCE to recover 90% of its environmental remediation costs at certain sites (SCE may request to include additional sites) and $82 million through a mechanism that allows SCE to recover 100% of the costs incurred at certain sites 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.

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 the identified material sites and immaterial sites could exceed its recorded liability by up to $185 million and $6 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.

SCE expects to clean up and mitigate its identified sites over a period of up to 30 years. Remediation costs for 2012 and in each of the next four years are expected to range from $7 million to $14 million. Costs incurred for the nine months ended September 30, 2012 and 2011 were $5 million and $9 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.

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Nuclear Insurance

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

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

NEIL, a mutual insurance company owned by entities with nuclear facilities, issues primary property damage, decontamination and excess property damage and accidental outage insurance policies. At San Onofre and Palo Verde, property damage insurance covers losses up to $500 million, including decontamination costs. Decontamination liability and excess property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than the federal requirement of a minimum of approximately $1.1 billion. Property damage insurance also covers damages caused by acts of terrorism up to specified limits. Additional outage insurance covers part of replacement power expenses during an accident-related nuclear unit outage.

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 $49 million per year. Insurance premiums are charged to operating expense.

Wildfire Insurance

Severe wildfires in California have given rise to large damage claims against California utilities for fire-related losses alleged to be the result of the failure of electric and other utility equipment. Invoking a California Court of Appeal decision, plaintiffs pursuing these claims have relied on the doctrine of inverse condemnation, which can impose strict liability (including liability for a claimant's attorneys' fees) for property damage. On September 15, 2012, SCE's parent, Edison International, renewed its insurance coverage, which included coverage for SCE's wildfire liabilities up to a $550 million limit (with a self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up the insurance coverage could result in additional self-insured costs in the event of multiple wildfire occurrences during the policy period (September 15, 2012 to August 31, 2013). SCE may experience coverage reductions and/or increased insurance costs in future years. No assurance can be given that future losses will not exceed the limits of SCE's insurance coverage.

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 the San Onofre 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. SCE received payment from the federal government in the amount of the damage award in November 2011. SCE has returned to the San Onofre co-owners their respective share of the damage award paid. SCE, as operating agent, filed a lawsuit on behalf of the San Onofre owners against the DOE in the Court of Federal Claims in December 2011 seeking damages of approximately $98 million for the period from January 1, 2006 to December 31, 2010 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel. Additional legal action would be necessary to recover damages incurred after December 31, 2010. Any damages recovered by SCE are subject to CPUC review as to how these amounts would be distributed among customers, shareholders, or to offset fuel decommissioning or storage costs.

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Note 10.    Environmental Developments

Cross-State Air Pollution Rule

In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated the US EPA's Cross-State Air Pollution Rule ("CSAPR") and directed the US EPA to continue administering the Clean Air Interstate Rule pending the promulgation of a valid replacement. In October 2012, the US EPA filed a petition seeking to have the decision reviewed by the full District of Columbia Circuit.

Hazardous Air Pollutant Regulations

In December 2011, the US EPA announced the Mercury and Air Toxics Standards rule, limiting emissions of hazardous air pollutants from coal- and oil-fired electrical generating units. The rule was published in the Federal Register on February 16, 2012, and became effective on April 16, 2012. A number of parties have filed notices of appeal challenging the rule.

Greenhouse Gas Regulation

In March 2012, the US EPA announced proposed carbon dioxide emissions limits for new power plants. The status of the US EPA's efforts to develop greenhouse gas emissions performance standards for existing plants is unknown.

In June 2012, the U.S. Court of Appeals for the D.C. Circuit dismissed the challenge by industry groups and some states to the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, known as the "GHG tailoring rule." In August 2012, states and industry groups challenging the rule filed a petition seeking to have the decision reviewed by the full District of Columbia Circuit.

In July 2012, the US EPA published a final rule maintaining the CO₂ equivalent emissions thresholds (for purposes of PSD and Title V permitting) originally established in the GHG tailoring rule.

Greenhouse Gas Litigation

In March 2012, the federal district court in Mississippi dismissed, in its entirety, the purported class action complaint filed by private citizens in May 2011, naming a large number of defendants, including SCE, EME and other Edison International subsidiaries, for damages allegedly arising from Hurricane Katrina. In April 2012, the plaintiffs filed an appeal with the Fifth Circuit Court of Appeals. 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.

In September 2012, a three-judge panel of the U.S Court of Appeals for the Ninth Circuit affirmed the dismissal of a case brought against Edison International and other defendants, by the Alaskan Native Village of Kivalina. In October 2012, the plaintiffs requested a rehearing by a larger panel of Ninth Circuit judges.

Note 11.    Accumulated Other Comprehensive Loss

Edison International's accumulated other comprehensive loss consists of:

(in millions)	Unrealized 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, 2011	$	(34	)	$	(100	)	$	(5	)	$	(139	)
Change for 2012	(38		)	9			—			(29		)
Balance at September 30, 2012	$	(72	)	$	(91	)	$	(5	)	$	(168	)

Included in accumulated other comprehensive loss at September 30, 2012 was $7 million, net of tax, of unrealized gains on commodity-based cash flow hedges, and $79 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 through December 31, 2013.

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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 $3 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.

Note 12.    Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

	Nine months ended September 30,
(in millions)	2012			2011
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	550		$	529
Tax refunds – net	(71		)	(330		)
Noncash investing and financing activities:
Details of debt exchange:
Pollution-control bonds redeemed	$	—		$	(86	)
Pollution-control bonds issued	—			86
Dividends declared but not paid:
Common stock	$	106		$	104
Preferred and preference stock	6			12

Accrued capital expenditures at September 30, 2012 and 2011 were $431 million and $393 million, respectively. Accrued capital expenditures will be included as an investing activity in the consolidated statements of cash flow in the period paid.

Note 13.    Preferred and Preference Stock of Utility

During the first quarter of 2012, SCE issued 350,000 shares of 6.25% Series E Preference Stock (cumulative, $1,000 liquidation value). The Series E preference shares may not be redeemed prior to February 1, 2022. After February 1, 2022, SCE may at its option, redeem the shares, in whole or in part for a price of $1,000 per share plus accrued and unpaid dividends, if any. The shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used to repay commercial paper borrowings and to fund SCE's capital program.

During the second quarter of 2012, SCE issued 190,004 shares of 5.625% Series F Preference Stock (cumulative, $2,500 liquidation value) to SCE Trust I, a special purpose entity formed to issue trust securities as discussed in Note 3. Variable Interest Entities. The Series F Preference Stock may not be redeemed prior to June 15, 2017. After June 15, 2017, SCE may at its option, redeem the shares, in whole or in part for a price of $2,500 per share plus accrued and unpaid dividends, if any. The shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used to repay commercial paper borrowings, for general corporate purposes and to redeem and retire $75 million of the Series A Preference Stock.

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Note 14.    Regulatory Assets and Liabilities

Regulatory Assets

Regulatory assets included on the consolidated balance sheets are:

(in millions)	September 30, 2012		December 31, 2011
Current:
Regulatory balancing accounts	$	108	$	223
Energy derivatives	141		264
Other	1		7
Total Current	250		494
Long-term:
Deferred income taxes – net	2,148		2,020
Pensions and other postretirement benefits	1,657		1,703
Energy derivatives	573		487
Unamortized investments – net	484		484
Unamortized loss on reacquired debt	233		249
Nuclear-related investment – net	145		156
Regulatory balancing accounts	102		69
Other	335		298
Total Long-term	5,677		5,466
Total Regulatory Assets	$	5,927	$	5,960

Regulatory Liabilities

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	September 30, 2012		December 31, 2011
Current:
Regulatory balancing accounts	$	478	$	661
Other	15		9
Total Current	493		670
Long-term:
Costs of removal	2,745		2,697
Asset Retirement Obligations	1,378		1,105
Regulatory balancing accounts	1,119		864
Other	7		4
Total Long-term	5,249		4,670
Total Regulatory Liabilities	$	5,742	$	5,340

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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 through 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, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Stocks	—	$	957	$	865	$	2,227	$	1,899
Municipal bonds	2054	520		625		654		756
U.S. government and agency securities	2042	526		516		589		580
Corporate bonds	2054	287		259		374		317
Short-term investments and receivables/payables	One-year	147		38		153		40
Total		$	2,437	$	2,303	$	3,997	$	3,592

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Proceeds from sales of securities (which are reinvested) were $428 million and $962 million for the three months ended September 30, 2012 and 2011, respectively, and $1.5 billion and $2.1 billion for the nine months ended September 30, 2012 and 2011, respectively. Unrealized holding gains, net of losses, were $1.6 billion and $1.3 billion at September 30, 2012 and December 31, 2011, 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)	2012			2011			2012			2011
Balance at beginning of period	$	3,810		$	3,657		$	3,592		$	3,480
Gross realized gains	13			46			54			81
Gross realized losses	—			(5		)	(5		)	(5		)
Unrealized gains (losses) – net	156			(305		)	272			(199		)
Other-than-temporary impairments	(7		)	(22		)	(30		)	(35		)
Interest, dividends, contributions and other	25			22			114			71
Balance at end of period	$	3,997		$	3,393		$	3,997		$	3,393

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)	2012		2011		2012		2011
Other income:
Equity allowance for funds used during construction	$	23	$	18	$	71	$	74
Increase in cash surrender value of life insurance policies	6		6		20		19
Other	7		2		12		10
Total utility other income	36		26		103		103
Competitive power generation and other income	1		1		2		7
Total other income	$	37	$	27	$	105	$	110
Other expenses:
Civic, political and related activities and donations	$	5	$	6	$	22	$	21
Other	4		4		14		14
Total utility other expenses	9		10		36		35
Competitive power generation and other expenses	1		1		—		2
Total other expenses	$	10	$	11	$	36	$	37

Note 17.    Planned Sale of Interest in Four Corners

In November 2010, SCE entered into an agreement to sell its ownership interest in Units 4 and 5 of the Four Corners Generating Station, a coal-fired electric generating facility in New Mexico, to the operator of the facility, Arizona Public Service Company. During 2012, the CPUC and the Arizona Corporation Commission ("ACC") approved the transaction. As part of its sale approval, the ACC stipulated that the sale cannot close earlier than December 1, 2012 which under the adjustment mechanism set forth in the sales agreement would reduce the sale price from $294 million to $279 million. The price is also subject to further adjustments. The closing of the sale is contingent upon the receipt of other specified closing conditions, including APS obtaining a long-term fuel supply agreement for the plant. The sale agreement provides for either party to terminate if it is not completed by December 31, 2012. Any gain on the sale will be for the benefit of SCE's customers and, therefore, will not affect SCE's earnings.

Note 18.    Discontinued Operations

On September 21, 2012, Homer City and an affiliate of GECC entered into the Homer City MTA for the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities. On October 3, 2012, GECC entered into a Plan Support Agreement ("the PSA") with the holders of approximately 76% of the outstanding principal amount of the secured lease obligation bonds issued by Homer City Funding, LLC as part of the original sale-leaseback transaction. Under the PSA, the parties committed to support and implement a reorganization plan of Homer City Funding, LLC and to solicit votes on a prepackaged plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 5, 2012, GECC commenced the solicitation. Homer City Funding, LLC is an affiliate of GECC and not related to Homer City or any other EME affiliate.

Completion of the Homer City MTA is subject to the satisfaction of a number of closing conditions, including the successful restructuring and reorganization of Homer City Funding, LLC and receipt of the regulatory approvals required for the transfer of the Homer City plant to GECC. If an agreement to modify the terms of the bonds is not approved and consummated or if other closing conditions of the Homer City MTA are not met, Homer City may become the subject of bankruptcy proceedings.

EME recorded an impairment charge of $1.03 billion related to Homer City's long-lived assets during the fourth quarter of 2011. Beginning in the third quarter of 2012, Homer City met the definition of a discontinued operation and was classified separately in Edison International's consolidated financial statements. EME recorded a $113 million charge ($68 million after tax) to write down assets held for sale to net realizable value during the third quarter of 2012.

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Summarized results of discontinued operations are as follows:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Total operating revenues	$	121		$	159		$	303		$	409
Total operating expenses	(138		)	(134		)	(385		)	(409		)
Asset impairment and other charges	(113		)	—			(134		)	—
Other income (expense)	5			2			7			(1		)
Income (loss) before income taxes	(125		)	27			(209		)	(1		)
Provision (benefit) for income taxes	(49		)	12			(80		)	2
Income (loss) from operations of discontinued operations	$	(76	)	$	15		$	(129	)	$	(3	)

The assets and liabilities associated with the discontinued operations are segregated on the consolidated balance sheets at September 30, 2012 and December 31, 2011. The carrying amount of the major components of asset and liability of discontinued operations are as follows:

(in millions)	September 30, 2012			December 31, 2011
Cash and cash equivalents	$	55		$	79
Other current assets	114			128
Carrying value adjustment	(108		)	—
Total current assets	61			207
Other long-term assets	—			45
Assets of discontinued operations	61			252
Total current liabilities	61			27
Other long-term liabilities	—			9
Liabilities of discontinued operations	$	61		$	36

Note 19.    EME Liquidity and Restructuring Activities

At September 30, 2012, EME, and its subsidiaries without contractual dividend restrictions, had corporate cash and cash equivalents of $627 million, which includes Midwest Generation's cash and cash equivalents of $142 million. At September 30, 2012, EME had $3.7 billion of unsecured notes outstanding, $500 million of which mature in June 2013.

EME continues to experience operating losses due to low realized energy and capacity prices, high fuel costs and low generation at the Midwest Generation plants. Forward market prices indicate that these trends are expected to continue for a number of years. As a result, EME expects that it will incur further reductions in cash flow and losses in the current year and in subsequent years. A continuation of these adverse trends coupled with pending debt maturities and the need to retrofit its Midwest Generation plants to comply with governmental regulations will exhaust EME's liquidity. Consequently, EME has been considering all options available to it, including potential sales of assets, restructuring, reorganization of its capital structure, or conservation of cash that would be applied otherwise to the payment of obligations.

In June 2012, EME entered into non-disclosure and engagement agreements with advisors representing holders of a majority in principal amount of its unsecured bonds for the purpose of engaging in discussions with such advisors and Edison International regarding EME's financial condition. In October 2012, EME and Edison International entered into non-disclosure agreements with certain of the clients of such advisors to facilitate further discussions. Discussions with the bondholders' advisors have been ongoing. In addition, EME and Midwest Generation have entered into a non-disclosure agreement with an advisor representing a majority in principal amount of Midwest Generation's senior lease obligation bonds.

Based on current projections, EME is not expected to have sufficient liquidity to repay the $500 million debt obligation due in June 2013. On November 15, 2012, $97 million of interest payments are due on unsecured EME bonds maturing in 2017, 2019 and 2027, and there is no assurance payment will be made. EME's unsecured bonds generally provide for a 30-day

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grace period for interest payments. EME's failure to pay indebtedness under its unsecured bonds would likely result in EME's filing for protection under Chapter 11 of the U.S. Bankruptcy Code, which would trigger cross defaults under EME's guarantee of the lease obligations of Midwest Generation, as well as Midwest Generation's own obligations under the lease and under instruments governing the senior lease obligation bonds, and which could potentially give rise to counterparty rights and remedies under other documents.

Under the applicable accounting standards, Edison International would no longer consolidate EME for financial reporting purposes if it filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code, as Edison International would no longer have a controlling financial interest for accounting purposes. In order to deconsolidate EME for financial reporting purposes, the carrying values of the assets and liabilities of EME would be removed from Edison International's consolidated balance sheets as of the bankruptcy filing date and the investment in EME would be recorded at its estimated fair value. Any loss would be recognized in an amount equal to the excess of the book value of Edison International's investment in EME over the fair value of such investment. At September 30, 2012, the book value of Edison International's investment in EME was $1.24 billion. Any amounts recorded as part of accumulated other comprehensive loss related to EME would be recognized as a loss upon deconsolidation. At September 30, 2012, the amount recorded as accumulated other comprehensive loss related to EME was $128 million. In addition, Edison International would record any liabilities due to EME and certain liabilities that are joint and several with EME, including liabilities for uncertain tax positions taken in consolidated or combined tax returns of Edison International that are otherwise not resolved through the tax-allocation agreement and certain retirement plans. Under current regulations, during bankruptcy, EME would continue to be consolidated with Edison International for federal income tax purposes until a change in ownership occurred.

Note 20.    Business Segments

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)	2012			2011			2012			2011
Operating Revenue:
Electric utility	$	3,731		$	3,386		$	8,794		$	8,063
Competitive power generation	340			437			1,009			1,277
Parent and other2	(1		)	(1		)	(3		)	(3		)
Consolidated Edison International	$	4,070		$	3,822		$	9,800		$	9,337
Net Income (Loss) attributable to Edison International:
Electric utility	$	363		$	406		$	736		$	838
Competitive power generation1	(137		)	33			(331		)	(17		)
Parent and other2	(36		)	(13		)	(48		)	(19		)
Consolidated Edison International	$	190		$	426		$	357		$	802

Segment balance sheet information was:

(in millions)	September 30, 2012			December 31, 2011
Total Assets:
Electric utility	$	43,059		$	40,315
Competitive power generation	7,934			8,392
Parent and other2	(448		)	(668		)
Consolidated Edison International	$	50,545		$	48,039

¹  Includes earnings (losses) from discontinued operations of $(76) million and $15 million for the three months ended September 30, 2012 and 2011, respectively, and $(129) million and $(3) million for the nine months ended September 30, 2012 and 2011, 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, CAIR and the MATS rule;

• 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 inherent in the construction of transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable the acceptance of power delivery), and governmental approvals;

• 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;

• risk that Units 2 and/or Unit 3 at San Onofre may not recommence operations or may require extensive repairs or replacement of the steam generators; with the cost of the related outcome not being recoverable from SCE's supplier, insurance coverage or through regulatory processes;

• ability of EME to meet its liquidity requirements, restructure its debt obligations and stabilize its capital structure during periods of operating losses and capital spending programs;

• completion of the transactions for the divestiture of Homer City's leasehold interest and related assets and liabilities pursuant to the terms of the Homer City MTA between Homer City and GECC, and the timing and structure of such transactions;

• cost and availability of electricity, including the ability to procure sufficient resources to meet expected customer needs to replace power that would have been provided by San Onofre but for the current outage or in the event of other power plant outages or 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;

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• 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 or in the absence of insurance the ability to recover uninsured losses;

• effects of legal proceedings, changes in or interpretations of tax laws, rates or policies;

• potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;

• cost and availability of coal, natural gas, fuel oil, and nuclear fuel, and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;

• cost and availability of emission credits or allowances for emission credits;

• transmission congestion in and to each market area and the resulting differences in prices between delivery points;

• ability to provide sufficient collateral in support of hedging activities and power and fuel purchased;

• risk that competing transmission systems will be built by merchant transmission providers in SCE's service area; 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 2011 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 2011 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.

The MD&A for the three- and nine-month periods ended September 30, 2012 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2011, and as compared to the three- and nine-month periods ended September 30, 2011. This discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2011 (the "year-ended 2011 MD&A"), which was included in the 2011 Form 10-K.

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EDISON INTERNATIONAL OVERVIEW

Highlights of Operating Results

	Three months ended September 30,									Nine months ended September 30,
(in millions)	2012			2011			Change			2012			2011			Change
Net Income (Loss) attributable to      Edison International
SCE	$	363		$	406		$	(43	)	$	736		$	838		$	(102	)
EMG	(137		)	33			(170		)	(331		)	(17		)	(314		)
Edison International Parent and Other	(36		)	(13		)	(23		)	(48		)	(19		)	(29		)
Edison International Consolidated	190			426			(236		)	357			802			(445		)
Less: Non-Core Items
EMG – Gain on sale of lease interest	31			—			31			31			—			31
EME's discontinued operations	(76		)	15			(91		)	(129		)	(3		)	(126		)
Total non-core items	(45		)	15			(60		)	(98		)	(3		)	(95		)
Core Earnings (Losses)
SCE	363			406			(43		)	736			838			(102		)
EMG	(92		)	18			(110		)	(233		)	(14		)	(219		)
Edison International Parent and Other	(36		)	(13		)	(23		)	(48		)	(19		)	(29		)
Edison International Consolidated	$	235		$	411		$	(176	)	$	455		$	805		$	(350	)

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 Edison International's 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. EMG classified the results of Homer City, including the costs incurred in connection with the expected divestiture, as non-core for both the three and nine months ended 2012 and 2011 due to the plan described below to transition ownership of the leasehold interest to the owner-lessors.

SCE's 2012 core earnings decreased $43 million and $102 million for the quarter and year-to-date, respectively. Core earnings in both periods decreased primarily due to a delay in the 2012 CPUC General Rate Case decision as higher depreciation and net interest expenses are not being recovered in currently authorized revenue, as well as higher costs at San Onofre. SCE has incurred $48 million and $96 million of incremental steam generator inspection and repair costs related to outages at San Onofre for the quarter and year-to-date periods in 2012, respectively, and $30 million in severance costs. These costs were partially offset by other operations and maintenance cost reductions in both periods. The revenue requirement ultimately adopted by the CPUC will be retroactive to January 1, 2012.

EMG's 2012 core losses increased $110 million and $219 million for the quarter and year-to-date, respectively. The increase in core losses was primarily due to lower average realized energy and capacity prices and lower generation at the Midwest Generation plants, decreased earnings from natural gas-fired projects and lower income tax benefits.

Edison International Parent and Other core losses increased $23 million and $29 million for the quarter and year-to-date, respectively. The increase in core losses was primarily due to higher consolidated state income taxes.

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Consolidated non-core items for 2012 and 2011 for Edison International included:

• $113 million pre-tax charge ($68 million after tax) associated with the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities. Pursuant to the Homer City MTA, beginning in the third quarter of 2012, Homer City met the definition of a discontinued operation and was classified separately in Edison International's consolidated statement of operations.

• In August 2012, Edison Capital sold its lease interest in Unit No. 2 of the Beaver Valley Nuclear Power Plant to a third party for $108 million and recorded a pre-tax gain of $65 million ($31 million after tax).

Management Overview of SCE

2012 CPUC General Rate Case

As discussed in the year-ended 2011 MD&A, SCE's 2012 GRC application, which requested a 2012 base rate revenue requirement of $6.29 billion, has been under submission to the CPUC.

On October 19, 2012, the CPUC assigned administrative law judge issued a proposed decision, which, if adopted, would result in a 2012 base rate revenue requirement of $5.69 billion, a decrease of $601 million from SCE's requested revenue requirement, primarily related to decreases in operations and maintenance expenses with some plant-related capital reductions, including potential disallowances of recorded capital investments for specific projects. The proposed decision, if adopted, would result in an increase of approximately $400 million over currently authorized revenue. The proposed decision approves San Onofre costs subject to refund and reasonableness review and includes a requirement to track those costs in a memorandum account. See “—San Onofre” below for further information. The proposed decision also accepts SCE's requested rate-making treatment of tax repair deductions. See "Edison International Notes to Consolidated Financial Statements—Note 7. Income Taxes" for further discussion.

The proposed decision would allow a post-test year ratemaking methodology that escalates capital additions by 3.05% for 2013 and 2.93% for 2014. It would also allow operations and maintenance expense to be escalated for 2013 and 2014 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology adopted in the proposed decision would result in a revenue requirement of $6.08 billion for 2013 and $6.43 billion for 2014.

SCE is currently recognizing revenue largely based on the 2011 authorized revenue requirement. The CPUC has authorized the establishment of a GRC memorandum account, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.

SCE is required to file comments within 20 days of receiving the proposed decision. The final CPUC decision could result in material changes to the proposed decision. A final CPUC decision is expected by year end.

2013 Cost of Capital Application

In June 2012, the CPUC issued an order in the 2013 Cost of Capital proceeding consolidating SCE's 2013 application with the three other California investor-owned utilities' applications and splitting the proceeding into two phases. The first phase will address the 2013 ratemaking capital structure and cost of capital for the utilities and contemplates a final decision in December 2012. The second phase will consider whether the current multi-year mechanism should be continued or modified. A final decision for the second phase is expected in April 2013.

SCE's 2013 cost of capital application, which was filed in April 2012, requested a ratemaking capital structure of 43% long-term debt, 9% preferred equity and 48% common equity consistent with the current capital structure. In October 2012, SCE submitted an update to its requested cost of capital further reducing its current cost of capital as follows: cost of long-term debt from 6.22% to 5.49%, authorized cost of preferred equity from 6.01% to 5.79% and authorized return on common equity from 11.5% to 11.1%. The application also requested the continuation of the current multi-year mechanism, which would have retained the authorized capital structure through 2015 with annual adjustments of the cost components if certain thresholds are reached.

San Onofre

Outage, Inspection and Repair Issues

As discussed in the 2011 Form 10-K, four replacement steam generators were installed at San Onofre Units 2 and 3 in 2010 and 2011, respectively. In the first quarter of 2012, a water leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. Unit 3 was safely taken off-line. At the time, San Onofre Unit 2 was off-line for a planned outage when areas of unexpected wear in some of its heat transfer tubes were found. Both Units have remained off-line for

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extensive inspections, testing and analysis of their steam generators. Each Unit will be restarted only when and if SCE determines that it is safe to do so and when start-up has been approved by the NRC pursuant to the terms of a Confirmatory Action Letter (“CAL”) issued by the NRC in March 2012. The CAL requires NRC permission to restart Unit 2 and Unit 3 and outlines actions SCE must complete before permission to restart either Unit may be sought. In October 2012, SCE submitted to the NRC a response to the CAL and restart plans for Unit 2 as described below.

Tube Leak and Repairs

The water leak in the Unit 3 steam generator was caused by excessive wear resulting from tube-to-tube contact in the area of the leak. During the inspection and testing of the Unit 3 steam generators, additional pressure tests of certain tubes were completed to determine the safety significance of the wear. Eight of the 129 tubes subjected to the additional tests failed the tests for structural integrity as a result of excessive wear, and the NRC was notified as required. The same areas were re-inspected in the Unit 2 steam generators using a more sensitive inspection method than had previously been employed, and similar wear from tube-to-tube contact was found on two tubes in one of the steam generators at wear levels below the detection capability of the initial inspection. Earlier tests performed on the Unit 2 steam generators during the planned outage additionally found levels of unexpected wear at points where some tubes were in contact with retainer bars of the tube support structure. Subsequent inspections on Unit 3 found similar tube-to-support structure wear.

As a result of these findings, SCE has plugged and removed from service all tubes showing excessive wear in each of the steam generators. In addition, SCE preventively plugged all tubes in contact with retainer bars or in the area of the tube bundles where tube-to-tube contact occurred. Each steam generator has over 9,700 heat transfer tubes and is designed to include sufficient tubes to accommodate a need to remove some from service for a variety of reasons, and the tubes that SCE has removed from service are within this margin.

A team of outside experts was assembled to assist SCE and Mitsubishi Heavy Industries, Inc. (“MHI”), the manufacturer of the steam generators, in the analysis of the causes of the tube-to-tube wear and potential remedial actions. As a result of their work, SCE understands that the tube-to-tube contact arises from excessive vibration of the tubes in certain areas of the steam generators. The excessive vibration that caused the tube-to-tube wear on Unit 3 resulted from a phenomenon called fluid elastic instability. This phenomenon arises from a combination of thermal hydraulic conditions (steam velocity and moisture content of the steam), and ineffectiveness of the tube supports in the areas where the vibration occurs. Unit 2 is susceptible to the same thermal hydraulic conditions as Unit 3, but the Unit 2 supports largely remained effective for the entire time that it operated as compared to Unit 3. This difference is likely the result of manufacturing differences between the pairs of steam generators in the two Units.

SCE's restart plans for Unit 2 and its response to the CAL are based on work done by engineering groups of three independent firms with expertise in steam generator design and manufacturing. Restart plans for only Unit 2 were submitted because of the extensive tube-to-tube wear in Unit 3, which was not experienced in Unit 2 (in which only one point of tube-to-tube wear between two tubes was identified). Using different methodologies, each independent outside engineering group concluded that it would be safe to restart Unit 2 and operate at a reduced power level (70%) for approximately five months, followed by a mid-cycle scheduled outage. The power level is being reduced to avoid the steam velocity and moisture content conditions that cause fluid elastic instability. The five month operating period is less than half the time Unit 3 operated and was validated by the independent experts as providing a safety margin to provide assurance of safe operation. In addition to these requirements, the restart plan covers repairs, corrective actions and operating parameters and also includes additional monitoring, detection and response activities.

Inasmuch as Unit 3 had much more tube-to-tube wear than Unit 2, it is not clear at this time whether Unit 3 will be able to restart without extensive additional repairs and corrective actions. Unit 3 will not restart this year and it is uncertain when or whether a restart plan will be submitted. The Unit 3 reactor is de-fueled and SCE is placing appropriate systems in a lay-up condition while analysis and testing continue. SCE is also engaged in the analysis of what repairs, if any, could be undertaken to restore the steam generators on both Units to their originally specified capabilities safely, but it has not determined what those repairs might be or whether the generators will need to be replaced for the Units to operate at their prior output levels. Each Unit will only be restarted when any necessary repairs and appropriate mitigation plans for that Unit are completed in accordance with the CAL, and the NRC and SCE are satisfied that it is safe to do so.

NRC Processes

The timing of restart of the Units will also be affected by the nature of and schedule for regulatory processes required by the NRC. There is no set or predetermined time period for approval of Unit 2's proposed restart, and, accordingly, there can be no assurance about the length of time the NRC may take to review SCE's request to restart or whether any such request would be granted in whole or in part.

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The NRC will conduct one or more on-site inspections to verify that SCE has performed the actions described in the CAL response and will hold public meetings to discuss the CAL response as well as the results of the on-site inspections. There is no timeline for the NRC's review of the CAL response. It is also possible that one or more amendments to the NRC operating license for San Onofre might be required (whether or not as a prerequisite to return a Unit to safe operation). The NRC could also choose to impose additional processes and assessments that could result in significant costs or additional delay.

Following the failure of pressure tests on the eight tubes in Unit 3, the NRC launched an Augmented Inspection Team (“AIT”) to assess the tube failures and their causes, SCE's operation of the Units, and SCE's oversight of the design, fabrication, shipping, and construction process. In July 2012, the NRC issued a report providing the results of the AIT inspection. That report concluded that the replacement steam generators' design and configuration did not provide the necessary margin to prevent fluid elastic instability and that these deficiencies appear to be related to MHI's computer code used to model thermal hydraulic conditions in the steam generators. The report further stated that SCE was adequately pursuing the causes of the unexpected steam generator tube-to-tube degradation. The AIT report also identified a number of as-yet unresolved issues that are continuing to be examined. The unresolved issues include further evaluation of manufacturing differences between Unit 2 and Unit 3, with particular focus on the control of critical dimensions affecting the clearances between tubes and tube supports. The NRC will conduct subsequent inspections or reviews to determine what, if any, regulatory actions result from these unresolved items. Should the NRC find a deficiency in SCE's performance, SCE could be subject to additional NRC actions, and the findings could be taken into consideration in the CPUC regulatory proceedings described below.

CPUC Review

Under California Public Utilities Code Section 455.5, SCE is required to notify the CPUC if either of the San Onofre Units has been out of service for nine consecutive months (not including preplanned outages). SCE will provide such notice to the CPUC on November 1, 2012 for Unit 3 and expects to do so by December 6, 2012 for Unit 2. The CPUC is required within 45 days of SCE's notice for a particular Unit to initiate an investigation to determine whether to remove from customer rates some or the entire revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such rates are collected subject to refund. Under Section 455.5 any determination to adjust rates is made after hearings are conducted in connection with the utility's next general rate case. If, after investigation and hearings, the costs associated with a Unit are disallowed recovery because it is out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation.

In October 2012, in advance of SCE's required notification under Section 455.5, the CPUC issued an order instituting investigation that will consolidate all San Onofre issues in related regulatory proceedings and consider appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, market power costs, capital and operations and maintenance costs, and seismic study costs. The order requires that all San Onofre-related costs incurred on and after January 1, 2012 be tracked in a memorandum account and, to the extent included in rates, collected subject to refund. The order also states that the CPUC will determine whether to order the immediate removal, effective as of the date of the order, of all costs related to San Onofre from SCE's rates, with placement of those costs in a deferred debit account pending the return of one or both Units to useful service, or other possible action. SCE will file its response to the order by November 26, 2012. SCE must also file testimony by December 10, 2012 detailing proposed rate adjustments due to the outages, including the amount of San Onofre costs in current rates, the amount to be removed, if any, the effective date, and related information. A pre-hearing conference will be scheduled early in 2013 after the issuance of a Scoping Memo by the Assigned Commissioner.

In parallel with the order instituting investigation, the 2012 GRC proposed decision would, if adopted, require SCE to track San Onofre-related costs in a memorandum account subject to refund, beginning January 1, 2012. SCE would be required by January 30, 2013 to file an application for reasonableness review of these costs and the proposed decision would allow that application to be consolidated with other proceedings. The 2012 GRC proposed decision also approves expenditures incurred through 2011 for the high pressure turbine project, but disallows recovery for post-2011 expenditures associated with the project and directs SCE to record those costs in either the memorandum account or seek future rate recovery in the next GRC. SCE anticipates that the inter-relationship between the Section 455.5 process and the issues to be reviewed in the investigation or pursuant to a final decision in the GRC will be addressed by the CPUC as it continues to develop the scope of the issues to be consolidated within the investigation.

In addition to the amounts for inspection and repair and market power costs discussed below, SCE has collected through customer rates an estimated $625 million of revenue through third quarter 2012 (based on current authorized revenue requirements) associated with the plant. SCE's total 2012 San Onofre annual revenue requirement, including the 2012 GRC proposed decision, is approximately $820 million, made up of $170 million in refueling outage, nuclear fuel and decommissioning costs and $650 million for its direct operating and maintenance costs, depreciation and return on its

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investment in San Onofre Unit 2, Unit 3 and related common plant. At September 30, 2012, SCE's rate base and net investment associated with San Onofre were as set forth in the following table:

(in millions)	Unit 2			Unit 3			Common Plant			Total
Net investment
Net plant in service	$	593		$	418		$	261		$	1,272
Materials and supplies	—			—			99			99
Construction work in progress	77			141			76			294
Nuclear fuel	153			212			101			466
Net investment	$	823		$	771		$	537		$	2,131
Rate base
Net plant in service	$	593		$	418		$	261		$	1,272
Materials and supplies	—			—			99			99
Accumulated deferred income taxes	(95		)	(45		)	(66		)	(206		)
Amounts in rate base	$	498		$	373		$	294		$	1,165

In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million after adjustment for inflation) for SCE's 78.21% share of San Onofre to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $594 million through September 30, 2012 on the steam generator replacement project, including $95 million reflected in construction work in progress primarily related to the disposal of the replaced steam generators. Those expenditures remain subject to CPUC reasonableness review. Final costs for the project will not be known until after disposal of the original steam generators is completed.

As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre are being purchased in the market by SCE (commencing on February 1 for Unit 3 and March 5 for Unit 2). Market costs through September 30, 2012 were approximately $221 million, net of avoided nuclear fuel costs, and are recoverable through the ERRA balancing account subject to CPUC reasonableness review. Because of the uncertainties associated with when and at what output levels the Units will or may be returned to service, total potential market power costs cannot be estimated at this time.

Through September 2012, SCE's share of incremental inspection and repair costs totaled $96 million for both Units. At September 30, 2012, the repairs to restart Unit 2 at the reduced power levels described above have been substantially completed. The costs for Unit 2 may increase following NRC review under the CAL and any new developments that may result from further analysis, testing and inspection, and there is no assurance that start-up of Unit 2 will occur as described above. Total incremental repair costs associated with returning Unit 3 to service, and returning both Units to service at originally specified capabilities safely, remain uncertain.

Contractual Matters

The steam generators were designed and supplied by MHI and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. SCE's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include "the cost of replacement power." Such limitations in the contract are subject to applicable exceptions. In September 2012, SCE submitted an invoice to MHI for costs paid through June 30, 2012 in the amount of $45 million for both SCE's and the other co-owners' share of steam generator repair costs. SCE expects to continue to invoice MHI for costs incurred. No amounts have been recognized in the financial statements as of September 30, 2012.

San Onofre carries both property damage and outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of potential claims for loss recovery. The property damage policy (including excess coverage) provides insurance for certain costs and expenses resulting from “Accidental Property Damage” with a $2.5 million deductible and a $2.75 billion limit of liability. After a twelve week deductible period, the outage policy provides insurance for an outage caused by “Accidental Property Damage” of up to $3.5 million per week for each Unit (or $2.8 million per Unit per week if both Units are out because of the same "Accident"), with a $490 million limit for each Unit ($392 million each if both Units are out because of the same "Accident"). The NEIL policies have a number of exclusions and limitations that may

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reduce or eliminate coverage. For instance, coverage may be reduced or excluded if it is determined that the outage resulted from any condition which develops, progresses or changes over time, or from wear and tear. Further, costs to "make good" faulty workmanship or design and amounts collectible from third parties are excluded from the property damage policy. Proof of loss must be submitted within 12 months of the Accidental Property Damage under the property damage insurance and within 12 months of the end of the outage under the outage policy. In October 2012, SCE filed separate proofs of loss for Unit 2 and Unit 3 under the outage policy. Pursuant to these proofs of loss SCE is seeking the weekly indemnity amounts provided under the policy for each Unit. Because the outage is ongoing, SCE will supplement these proofs of loss in the future. No amounts have been recognized in SCE's financial statements, pending further actions by NEIL. To the extent any costs are recovered under the outage policy, SCE expects to refund those amounts to ratepayers through the ERRA balancing account. For further information, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

SCE will pursue recoveries arising from available agreements, but there is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements.

CAISO Summer Readiness Planning

In addition to providing up to 2,200 MW of electric power, San Onofre also provides significant reliability support to the electric grid, including support for grid voltage and stability. SCE continues to work with the CAISO to maintain grid reliability for summer 2013 and beyond while the San Onofre Units are out of service. SCE is supporting CAISO in its negotiations to obtain local grid voltage support. SCE has also accelerated certain transmission projects and will expand its demand response programs to help maintain grid reliability. The majority of these efforts are projects that are already included in SCE's capital expenditure plan, but their timing has been accelerated. In addition, SCE has proposed to the CAISO projects such as transmission line reconfiguration and installation of equipment to support voltage and stability. The projects, if approved could result in additional capital expenditures from $100 million to $125 million over the period 2013 – 2015.

Workforce Reduction

In August 2012, SCE announced plans for downsizing to bring the San Onofre organization and cost structure in line with industry peers. SCE plans to reduce the San Onofre workforce by 730 employees to 1,500 employees beginning in the fourth quarter of 2012 and continuing in 2013. At September 30, 2012, SCE had recorded $30 million in estimated cash severance costs (SCE's share) related to the non-represented employee workforce reduction.

Capital Program

During the first nine months of 2012, SCE's capital investment program focused on maintaining reliability and expanding the capability of SCE's transmission and distribution system; upgrading and constructing new transmission lines and substations; installing digital meters; and replacing generation asset equipment. Total capital expenditures (including accruals) were $2.6 billion during the first nine months of 2012 compared to $2.5 billion during the same period in 2011. SCE expects that 2012 capital expenditures will be below the lower end of the previously projected $4.4 billion to $5.0 billion range due to the delay in the GRC decision, the delay related to the Tehachapi Project and outages at San Onofre. However, SCE continues to project that 2012 – 2014 total capital expenditures will be in the range of $11.8 billion to $13.2 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; outcome of the San Onofre mitigation plans; and other factors.

Management Overview of EMG

EME Liquidity and Restructuring Activities

EME's operating loss increased significantly in the nine months ended September 30, 2012 compared to the same period in 2011, primarily due to lower capacity and average realized energy prices, reduced generation and higher fuel prices at the Midwest Generation plants. The abundance of low-priced natural gas has continued to result in increased competition from natural gas-fired generating units in the markets in which Midwest Generation operates, and generation has been correspondingly affected. In addition, effective January 1, 2012, a favorable long-term rail contract that supplied Midwest Generation's fleet expired and was replaced by a higher priced contract.

At September 30, 2012, EME, and its subsidiaries without contractual dividend restrictions, had corporate cash and cash equivalents of $627 million, which includes Midwest Generation's cash and cash equivalents of $142 million. At September 30, 2012, EME had $3.7 billion of unsecured notes outstanding, $500 million of which mature in June 2013.

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EME continues to experience operating losses due to low realized energy and capacity prices, high fuel costs and low generation at the Midwest Generation plants. Forward market prices indicate that these trends are expected to continue for a number of years. As a result, EME expects that it will incur further reductions in cash flow and losses in the current year and in subsequent years. A continuation of these adverse trends coupled with pending debt maturities and the need to retrofit its Midwest Generation plants to comply with governmental regulations will exhaust EME's liquidity. Consequently, EME has been considering all options available to it, including potential sales of assets, restructuring, reorganization of its capital structure, or conservation of cash that would be applied otherwise to the payment of obligations.

In June 2012, EME entered into non-disclosure and engagement agreements with advisors representing holders of a majority in principal amount of its unsecured bonds for the purpose of engaging in discussions with such advisors and Edison International regarding EME's financial condition. In October 2012, EME and Edison International entered into non-disclosure agreements with certain of the clients of such advisors to facilitate further discussions. Discussions with the bondholders' advisors have been ongoing. In addition, EME and Midwest Generation have entered into a non-disclosure agreement with an advisor representing a majority in principal amount of Midwest Generation's senior lease obligation bonds.

Based on current projections, EME is not expected to have sufficient liquidity to repay the $500 million debt obligation due in June 2013. On November 15, 2012, $97 million of interest payments are due on unsecured EME bonds maturing in 2017, 2019 and 2027, and there is no assurance payment will be made. EME's unsecured bonds generally provide for a 30-day grace period for interest payments. EME's failure to pay indebtedness under its unsecured bonds will likely result in EME's filing for protection under Chapter 11 of the U.S. Bankruptcy Code, which would trigger cross defaults under EME's guarantee of the lease obligations of Midwest Generation, as well as Midwest Generation's own obligations under the lease and under instruments governing the senior lease obligation bonds, and which could potentially give rise to counterparty rights and remedies under other documents.

Bankruptcy proceedings could lead to a change of control of EME, which would, among other things, result in the termination of EME's tax-allocation agreement. At September 30, 2012, EME had recognized $635 million of net tax benefits based on continued ownership by Edison International and inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries. If realization is unlikely, EME would record a valuation allowance to reduce the carrying value of these assets and record a material charge against earnings. The termination of the tax-allocation agreement could adversely affect EME's long-term liquidity because realization of the value of tax benefits generated by EME could be deferred until such time that EME, or a subsequent owner of EME, had the ability to utilize such benefits. There is no assurance as to when, or whether, this might occur.

Under the applicable accounting standards, Edison International would no longer consolidate EME for financial reporting purposes if it filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code, as Edison International would no longer have a controlling financial interest for accounting purposes. In order to deconsolidate EME for financial reporting purposes, the carrying values of the assets and liabilities of EME would be removed from Edison International's consolidated balance sheets as of the bankruptcy filing date and the investment in EME would be recorded at its estimated fair value. Any loss would be recognized in an amount equal to the excess of the book value of Edison International's investment in EME over the fair value of such investment. At September 30, 2012, the book value of Edison International's investment in EME was $1.24 billion. Any amounts recorded as part of accumulated other comprehensive loss related to EME would be recognized as a loss upon deconsolidation. At September 30, 2012, the amount recorded as accumulated other comprehensive loss related to EME was $128 million. In addition, Edison International would record any liabilities due to EME and certain liabilities that are joint and several with EME, including liabilities for uncertain tax positions taken in consolidated or combined tax returns of Edison International that are otherwise not resolved through the tax-allocation agreement and certain retirement plans. Under current regulations, during bankruptcy, EME would continue to be consolidated with Edison International for federal income tax purposes until a change in ownership occurred.

The accompanying consolidated financial statements have been prepared assuming that EME will continue as a going concern. Financial statements prepared on this basis assume the realization of assets and the satisfaction of liabilities in the normal course of business for the 12-month period following the date of these financial statements. There is no assurance that EME will be able to continue as a going concern.

Midwest Generation's Dependence on EME

Midwest Generation is largely dependent on EME to fund cash flow deficits and environmental retrofits. EME has no obligation to make capital contributions to Midwest Generation and may be unable to do so. Furthermore, Midwest Generation had $1.323 billion of notes receivable from EME at September 30, 2012 with payments used to meet its rent obligations under the Powerton and Joliet sale-leaseback agreements. If EME is unable to make payments on its notes,

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Midwest Generation may in turn be unable to make rent payments under the Powerton-Joliet leases. Failure to pay rent would be an event of default under the Powerton-Joliet leases that could result in termination of the leases, loss of control over the use of the Powerton and Joliet Stations and a claim for termination value under the lease agreements. Accordingly, if Midwest Generation is unable to obtain financial support from EME or other sources, Midwest Generation may need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. A bankruptcy of either EME or Midwest Generation would also be an event of default under the Powerton-Joliet leases.

Midwest Generation Environmental Compliance Plans and Costs

During the third quarter of 2012, Midwest Generation continued to develop and implement a compliance program that includes the operation of ACI systems for mercury removal, upgrades to particulate removal systems and the use of dry sorbent injection, combined with the use of low sulfur PRB coal, to meet emissions limits for criteria pollutants, such as NO_x and SO₂ as well as for hazardous air pollutants, such as mercury, acid gas and non-mercury metals.

Apart from the Fisk and Crawford Stations, which ceased operations in September 2012, decisions whether or not to proceed with retrofitting of any particular remaining units to comply with CPS requirements for SO₂ emissions, including those that have received permits, are subject to a number of factors, such as market conditions, regulatory and legislative developments, liquidity and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation may also elect to shut down units, instead of installing controls, to be in compliance with the CPS. 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 will be made as required, subject to the requirements of the CPS and other applicable regulations. Units that are not retrofitted may continue to operate for as long as regulations and law allow.

Based on work to date, Midwest Generation estimates the remaining cost of retrofitting Powerton Units 5 and 6, Joliet Units 7 and 8 and Will County Units 3 and 4, using dry scrubbing with sodium-based sorbents and upgrading particulate removal systems, to be approximately $619 million at September 30, 2012. It is less likely that retrofits will be made to Joliet Unit 6 and the Waukegan Station. During the third quarter of 2012, the Pollution Control Board granted Midwest Generation's request to extend Waukegan Unit 7's unit specific retrofit requirements from December 31, 2013 to December 31, 2014. The estimated cost of retrofitting Joliet Unit 6, if made, would be approximately $75 million, while the estimated cost of retrofitting the Waukegan Station, if made, would be approximately $160 million. Final decisions to shut down units will be made in light of the timing requirements under the CPS and other applicable environmental regulations, based on the economic projections of those retrofits, on a unit-by-unit basis, at the time the decision is made. For further discussion related to the impairment policy on Midwest Generation's unit of account, refer to "Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets" in the year-ended 2011 MD&A.

Homer City Lease

On September 21, 2012, Homer City and an affiliate of GECC entered into the Homer City MTA for the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities. On October 3, 2012, GECC entered into a Plan Support Agreement (the PSA) with the holders of approximately 76% of the outstanding principal amount of the secured lease obligation bonds issued by Homer City Funding, LLC as part of the original sale-leaseback transaction. Under the PSA, the parties committed to support and implement a reorganization plan of Homer City Funding, LLC and to solicit votes on a prepackaged plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 5, 2012, GECC commenced the solicitation. Homer City Funding, LLC is an affiliate of GECC and not related to Homer City or any other EME affiliate. In addition, Homer City received a forbearance of the $47 million senior rent payment that had been due October 1, 2012 and was granted a waiver of the $65 million equity rent payment that had been due April 1, 2012.

Completion of the Homer City MTA is subject to the satisfaction of a number of closing conditions, including the successful restructuring and reorganization of Homer City Funding, LLC and receipt of the regulatory approvals required for the transfer of the Homer City plant to GECC. If an agreement to modify the terms of the bonds is not approved and consummated or if other closing conditions of the Homer City MTA are not met, Homer City may become the subject of bankruptcy proceedings.

Beginning in the third quarter of 2012, Homer City met the definition of a discontinued operation and EME recorded a $113 million charge ($68 million after tax) to write down assets held for sale to net realizable value during the third quarter of 2012.

For further discussion, see "Edison International Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Interim Financial Statements," "—Note 8. Compensation and Benefit Plans," and "—Note 18. Discontinued Operations."

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Environmental Developments

For a discussion of environmental developments, see "Edison International Notes to Consolidated Financial Statements—Note 10. 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 revenue authorized by the CPUC and FERC which is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution assets. The annual revenue requirements are comprised of authorized operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure. Also, included in utility earnings activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.

• Utility cost-recovery activities – representing CPUC- and FERC-authorized balancing accounts which allow for recovery of specific project or program costs, subject to reasonableness review or compliance with upfront standards.

The following tables summarize SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities. Beginning in 2012, SCE classified revenues and costs related to programs that provide for recovery of actual costs plus a return on capital as utility earning activities. Previously, SCE classified the recovery of actual costs incurred under these programs as utility cost-recovery activities. The tables presented below reflect a reclassification of the revenues and costs for 2011 consistent with the presentation in 2012. The reclassification of revenues and costs had no impact on earnings.

During the first nine months of 2012, pending the outcome of the 2012 GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement included in customer rates. This has resulted in a decrease in net income as higher depreciation and net interest expenses are not being recovered in currently authorized revenue. A GRC memorandum account has been established for SCE, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012. Recognition of the revenue for the period January 1, 2012 through the date of a final decision, as well as any delays in certain expenditures and changes in authorized treatment of specific costs, will impact the timing of earnings in 2012 (see "Edison International Overview—Management Overview of SCE—2012 CPUC General Rate Case" for further discussion).

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Three Months Ended September 30, 2012 versus September 30, 2011

	Three months ended September 30, 2012								Three months ended September 30, 2011
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated
Operating revenue	$	1,754		$	1,977	$	3,731		$	1,759		$	1,627	$	3,386
Fuel and purchased power	—			1,694		1,694			—			1,374		1,374
Operations and maintenance	623			283		906			566			253		819
Depreciation decommissioning and amortization	399			—		399			358			—		358
Property taxes and other	73			—		73			71			—		71
Total operating expenses	1,095			1,977		3,072			995			1,627		2,622
Operating income	659			—		659			764			—		764
Net interest expense and other	(95		)	—		(95		)	(98		)	—		(98		)
Income before income taxes	564			—		564			666			—		666
Income tax expense	176			—		176			245			—		245
Net income	388			—		388			421			—		421
Dividends on preferred and preference stock	25			—		25			15			—		15
Net income available for common stock	$	363		$	—	$	363		$	406		$	—	$	406
Core Earnings1						$	363							$	406
Non-Core Earnings						—								—
Total SCE GAAP Earnings						$	363							$	406

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

Utility Earning Activities

Utility earning activities were primarily affected by the following:

• Higher operations and maintenance expense of $57 million was primarily due to increased costs at San Onofre, including $48 million related to the steam generator inspection and repair at San Onofre and $30 million of estimated cash severance costs related to the planned San Onofre reduction in workforce; partially offset by lower operations and maintenance expenses. These increases were partially offset by EdisonSmartConnect^® benefits realized and other cost savings and timing of expenses.

• Higher depreciation, decommissioning and amortization expense of $41 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs.

• Lower income taxes due to lower pre-tax income. See "—Income Taxes" below for more information.

• Higher preferred and preference stock dividends of $10 million related to new issuances in 2012.

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Utility Cost-Recovery Activities

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

• Higher fuel and purchased power expense of $320 million was primarily driven by the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but which were included as a separate component on customer bills (see "—Supplemental Operating Revenue Information" below) and $104 million of market costs net of lower nuclear fuel costs related to the outage at San Onofre in 2012 (see "Edison International Overview—Management Overview of SCE—San Onofre" for further information). These increases were partially offset by lower power prices in 2012.

• Higher operations and maintenance expense of $30 million was primarily due to increased energy efficiency program costs.

Nine Months Ended September 30, 2012 versus September 30, 2011

	Nine months ended September 30, 2012									Nine months ended September 30, 2011
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated
Operating revenue	$	4,670		$	4,124		$	8,794		$	4,596		$	3,467	$	8,063
Fuel and purchased power	—			3,269			3,269			—			2,691		2,691
Operations and maintenance	1,774			848			2,622			1,675			775		2,450
Depreciation decommissioning and amortization	1,187			—			1,187			1,058			—		1,058
Property taxes and other	227			2			229			216			1		217
Total operating expenses	3,188			4,119			7,307			2,949			3,467		6,416
Operating income	1,482			5			1,487			1,647			—		1,647
Net interest expense and other	(296		)	(5		)	(301		)	(269		)	—		(269		)
Income before income taxes	1,186			—			1,186			1,378			—		1,378
Income tax expense	384			—			384			496			—		496
Net income	802			—			802			882			—		882
Dividends on preferred and preference stock	66			—			66			44			—		44
Net income available for common stock	$	736		$	—		$	736		$	838		$	—	$	838
Core Earnings1							$	736							$	838
Non-Core Earnings							—								—
Total SCE GAAP Earnings							$	736							$	838

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

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Utility Earning Activities

Utility earning activities were primarily affected by the following:

• Higher operating revenue of $74 million was primarily due to $80 million of increased revenue related to authorized CPUC projects not included in SCE's GRC process, including the EdisonSmartConnect^® project and the Solar Photovoltaic project (approximately $65 million primarily recovered operations and maintenance and depreciation expense associated with the related CPUC projects). The change in revenue also reflects revenue recognized in 2012 related to the San Onofre Unit 2 scheduled outage costs. In December 2011, the CPUC authorized revenue requirements for 2012 refueling outages for San Onofre. These increases were partially offset by decreases in other operating revenue.

• Higher operation and maintenance expense of $99 million was primarily due to increased costs at San Onofre, including $96 million of costs related to the steam generator inspection and repair as well as $35 million related to the 2012 San Onofre Unit 2 scheduled maintenance and refueling outage and $30 million of estimated cash severance costs related to the planned San Onofre reduction in workforce (see "Edison International Overview—Management Overview of SCE—San Onofre" for further information); partially offset by lower operations and maintenance expenses. These increases were partially offset by EdisonSmartConnect^® benefits realized and other cost savings and timing of expenses.

• Higher depreciation, decommissioning and amortization expense of $129 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs and CPUC capital-related projects discussed above.

• Higher net interest expense and other of $27 million was primarily due to higher outstanding balances on long-term debt.

• Lower income taxes due to lower pre-tax income. See "—Income Taxes" below for more information.

• Higher preferred and preference stock dividends of $22 million related to new issuances in 2012.

Utility Cost-Recovery Activities

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

• Higher fuel and purchased power expense of $578 million was primarily driven by the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but which were included as a separate component on customer bills (see "—Supplemental Operating Revenue Information" below) and $221 million of market costs net of lower nuclear fuel costs related to the San Onofre outage in 2012 (see "Edison International Overview—Management Overview of SCE—San Onofre" for further information). These increases were partially offset by lower power prices in 2012.

• Higher operation and maintenance expense of $73 million was primarily due to increased pension contributions.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $3.7 billion and $8.7 billion for the three- and nine-month periods ended September 30, 2012, respectively, compared to $3.3 billion and $7.8 billion for the respective periods in 2011. The increase in revenue reflects:

• A sales volume increase of $677 million and $1.4 billion for the three- and nine-month periods, respectively, primarily due to SCE providing power that was previously provided by CDWR contracts which expired in 2011. Prior to 2012, SCE remitted to CDWR and did not recognize as revenue the amounts that SCE billed and collected from its customers for the portion of electric power purchased and sold by the CDWR to SCE's customers.

• A rate decrease of $294 million and $502 million for the three- and nine-month periods, respectively, resulting from rate adjustments in June 2011 and August 2012, primarily reflecting lower forecasted fuel and purchased power costs and refunds to customers of overcollected fuel and power procurement-related costs.

As a result of the CPUC-authorized decoupling mechanism, SCE earnings are not affected by changes in retail electricity sales (see "Item 1. Business—Overview of Ratemaking Process" in the 2011 Form 10-K).

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

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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)	2012			2011			2012			2011
Income before income taxes	$	564		$	666		$	1,186		$	1,378
Provision for income tax at federal statutory rate of 35%	197			233			415			482
Increase (decrease) in income tax from:
State tax – net of federal benefit	10			31			30			61
Property-related	(19		)	(18		)	(39		)	(38		)
Other	(12		)	(1		)	(22		)	(9		)
Total income tax expense	$	176		$	245		$	384		$	496
Effective tax rate	31		%	37		%	32		%	36		%

State income taxes were lower for both the three- and nine-month periods ended September 30, 2012 due to lower pre-tax income and higher benefits related to depreciation, cost of removal and repair deductions, including additional tax deductions reflected in SCE's 2011 tax returns.

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

LIQUIDITY AND CAPITAL RESOURCES

SCE's ability to operate its business, fund capital expenditures, and implement its business strategy are dependent upon its cash flow and access to the capital markets. 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, interest and dividend payments to investors, and the outcome of tax and regulatory matters.

SCE expects to fund its 2012 obligations, capital expenditures and dividends through operating cash flows and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities to meet operating and capital requirements.

Available Liquidity

During the second quarter of 2012, SCE replaced its existing credit facilities scheduled to mature in early 2013 with a new $2.75 billion five-year revolving credit facility that matures May 2017. The following table summarizes the status of the SCE credit facility at September 30, 2012:

(in millions)	Credit Facilities
Commitment	$	2,750
Outstanding commercial paper supported by credit facilities	(380		)
Outstanding letters of credit	(196		)
Amount available	$	2,174

Debt Covenant

SCE has a debt covenant in its credit facility that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At September 30, 2012, SCE's debt to total capitalization ratio was 0.46 to 1.

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Capital Investment Plan

Transmission Projects - Tehachapi Project

As discussed in the year-ended 2011 MD&A, the CPUC requested that SCE provide information on potential new options for a portion of the Tehachapi Project, including traversing a state park, changing the nature of some of the towers and undergrounding lines. In July 2012, the Assigned Commissioner issued a ruling requesting SCE to further study and provide more detailed information by the end of February 2013 on two identified undergrounding options for a portion of the project. The ruling set forth a schedule for interested parties to also provide further information, briefing by all parties and evidentiary hearings. The order states that the construction of the affected portion of the project shall remain deferred until the CPUC makes a final determination regarding the options. Adoption of either of the two undergrounding options could create significant additional costs and delay the completion of the project. SCE is required to file revised cost estimates with the CPUC by the end of February 2013. As with all transmission investments, cost recovery will be subject to future rate proceedings.

Regulatory Proceedings

FERC Formula Rates

As discussed in the year-ended 2011 MD&A, the FERC has accepted, subject to refund and settlement procedures, SCE's request to implement formula rates as a means to determine SCE's FERC transmission revenue requirement effective January 1, 2012. SCE's request would result in a total 2012 FERC weighted average ROE of 11.1% including a base ROE of 9.93% and the previously authorized 50 basis point incentive for CAISO participation and individual authorized project incentives.

In September 2012, SCE filed its proposed formula rate update with the FERC. SCE's proposed request would implement a 2013 transmission revenue requirement of $900 million, representing an increase of $178 million or 25% over the 2012 revenue requirement. The increase is primarily due to higher FERC rate base from transmission investments, including projects under construction. Consistent with SCE's proposed formula rate methodology, the proposed revenue requirement utilizes the 2012 FERC authorized base ROE discussed above, which remains subject to refund and the ongoing settlement negotiations.

The formula rate mechanism, including the base ROE, is subject to final resolution as part of the settlement process or, if a settlement is not achieved, to determination by FERC in a litigated process. SCE and the other parties to the proceeding continue to engage in settlement negotiations.

Dividend Restrictions

The CPUC regulates SCE's capital structure which limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At September 30, 2012, SCE's 13-month weighted-average common equity component of total capitalization was 48.9% resulting in the capacity to pay $175 million in additional dividends to Edison International. During the first nine months of 2012, SCE made $349 million in dividend payments to its parent, Edison International.

Margin and Collateral Deposits

Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. Future collateral requirements may differ from the requirements at September 30, 2012, due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, and the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations.

Some of the power procurement contracts contain provisions that require SCE to maintain an investment grade credit rating from the major credit rating agencies. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the liability or post additional collateral.

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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, 2012.

(in millions)
Collateral posted as of September 30, 20121	$	249
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade	64
Posted and potential collateral requirements2	$	313

¹  Collateral provided to counterparties and other brokers consisted of $44 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $9 million of cash reflected in "Other current assets" on the consolidated balance sheets and $196 million in letters of credit.

²  Total posted and potential collateral requirements may increase by $14 million based on SCE's forward positions as of September 30, 2012 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

For a discussion of potential collateral requirements related to its self-insured workers compensation plan, refer to "SCE: Liquidity and Capital Resources—Workers Compensation Self-Insurance Fund" in the year-ended 2011 MD&A.

Historical Segment Cash Flows

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

	Nine months ended September 30,
(in millions)	2012			2011
Net cash provided by operating activities	$	2,656		$	2,272
Net cash provided by financing activities	636			672
Net cash used by investing activities	(3,259		)	(3,136		)
Net increase (decrease) in cash and cash equivalents	$	33		$	(192	)

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased $384 million in the first nine months of 2012 compared to the same period in 2011. The increase in cash flows provided by operating activities was primarily due to higher net tax receipts in 2012, the impact of higher costs at San Onofre and the timing of cash receipts and disbursements related to working capital items.

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Net Cash Provided by Financing Activities

The following table summarizes cash provided by financing activities for the nine months ended September 30, 2012 and 2011. Issuances of debt and preference stock are discussed in "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt" and "Note 12. Preferred and Preference Stock."

	Nine months ended September 30,
(in millions)	2012			2011
Issuances of first and refunding mortgage bonds, net	$	391		$	492
Net issuances of commercial paper1	(45		)	550
Issuances of preference stock, net	804			123
Payments of common stock dividends to Edison International	(349		)	(345		)
Redemptions of preference stock	(75		)	—
Bonds purchased	—			(86		)
Payments of preferred and preference stock dividends	(62		)	(43		)
Other	(28		)	(19		)
Net cash provided by financing activities	$	636		$	672

¹  Issuances of commercial paper are supported by SCE's credit facility.

The timing and amount of SCE's financing activities are largely driven by its capital program.

Net Cash Used by Investing Activities

Cash flows from investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $3.1 billion and $3.0 billion for the nine months ended September 30, 2012 and 2011, respectively (see "Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2011 MD&A for further information on capital expenditures). Net purchases of nuclear decommissioning trust investments and other were $164 million and $146 million for the nine months ended September 30, 2012 and 2011, respectively.

Contractual Obligations and Contingencies

Contractual Obligations

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

Contingencies

SCE has contingencies related to the San Onofre Outage, Inspection and Repair Issues, CPSD Investigations, Four Corners New Source Review Litigation, Nuclear Insurance, Wildfire 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, 2012, SCE had identified 25 material sites for remediation and recorded an estimated minimum liability of $113 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. Derivative instruments are used, as appropriate, to manage market risks for customers and SCE. 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 Instruments and Hedging Activities" and "—Note 4. Fair Value Measurements."

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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 $1.0 billion and $936 million at September 30, 2012 and December 31, 2011, respectively. To the extent San Onofre Unit 2 and Unit 3 are not operating, SCE may be exposed to market prices associated with replacement power costs. SCE's hedging program has taken this exposure into consideration and has entered into forward contracts to address projected market price variability. 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 arrangements. 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 arrangements, including master netting agreements. As of September 30, 2012, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:

	September 30, 2012
(in millions)	Exposure2		Collateral			Net Exposure
S&P Credit Rating1
A or higher	$	101	$	—		$	101
Not rated3	5		(1		)	4
Total	$	106	$	(1	)	$	105

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

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

³  The exposure in this category relates to long-term power purchase agreements. SCE's exposure is mitigated by regulatory treatment.

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EDISON MISSION GROUP

RESULTS OF OPERATIONS

EMG primarily operates in one line of business, independent power production, through the subsidiaries of EMG's principal subsidiary, EME. 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)	2012			2011			2012			2011
Competitive power generation operating revenues	$	340		$	437		$	1,009		$	1,277
Fuel	188			162			458			402
Operation and maintenance	164			173			572			634
Depreciation and amortization	67			72			202			213
(Gain) loss on sale of assets and other	(65		)	—			(60		)	8
Total operating expenses	354			407			1,172			1,257
Operating income (loss)	(14		)	30			(163		)	20
Interest and dividend income	1			1			14			31
Equity in income from unconsolidated affiliates – net	25			56			42			68
Other income, net	—			1			1			7
Interest expense	(83		)	(81		)	(253		)	(243		)
Income (loss) from continuing operations before income taxes	(71		)	7			(359		)	(117		)
Income tax benefit	(15		)	(11		)	(169		)	(102		)
Income (loss) from continuing operations	(56		)	18			(190		)	(15		)
Income (loss) from discontinued operations – net of tax	(76		)	15			(129		)	(3		)
Net income (loss)	(132		)	33			(319		)	(18		)
Other noncontrolling interests	5			—			12			(1		)
Net income (loss) available for common stock	$	(137	)	$	33		$	(331	)	$	(17	)
Core income (loss)1	$	(92	)	$	18		$	(233	)	$	(14	)
Non-Core losses:
Gain on sale of lease interest	31			—			31			—
Discontinued Operations	(76		)	15			(129		)	(3		)
Total EMG GAAP Income (Loss)	$	(137	)	$	33		$	(331	)	$	(17	)

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

EMG had a core loss in the third quarter of 2012 compared to core earnings in the third quarter of 2011 primarily due to the following pre-tax items:

• $117 million decrease in Midwest Generation results primarily due to lower capacity and average realized energy prices, reduced generation and higher fuel prices, partially offset by lower planned maintenance costs and lower depreciation.

• $29 million decrease in the Sunrise project results due to the transition off of a long-term power purchase agreement to merchant operations.

• $7 million decrease in renewable energy income primarily attributable to income allocated to third-party investors in Capistrano Wind Partners, partially offset by results of operations from projects that achieved commercial operations after the third quarter of 2011.

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The third quarter core loss was partially offset by the following pre-tax item:

• $10 million increase in energy trading due to higher revenues from trading power and MISO congestion contracts.

EMG's core loss for the nine months ended September 30, 2012 increased compared to the nine months ended September 30, 2011 primarily due to the following pre-tax items:

• $257 million decrease in Midwest Generation results primarily due to lower capacity and average realized energy prices, reduced generation and higher fuel prices, partially offset by lower planned maintenance costs and lower depreciation.

• $19 million decrease in the Sunrise project results due to the transition off of a long-term power purchase agreement to merchant operations.

• $15 million lower income from distributions received from the Doga project.

• $10 million increase in interest expense primarily due to new project financings.

• $7 million decrease in renewable energy income was attributable to income allocated to Capistrano Wind Partners, partially offset by results of operations from projects that achieved commercial operations after the third quarter of 2011.

EMG's non-core items for the nine months ended September 30, 2012 included:

• $113 million pre-tax charge ($68 million after tax) associated with the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities. Pursuant to the Homer City MTA, beginning in the third quarter of 2012, Homer City met the definition of a discontinued operation and was classified separately in Edison International's consolidated statements of income.

• $65 million pre-tax gain ($31 million after tax) associated with the Edison Capital's sale of its lease interest in Unit No. 2 of the Beaver Valley Nuclear Power Plant.

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Adjusted Operating Income (Loss) ("AOI")—Overview

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

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Midwest Generation plants	$	(48	)	$	69		$	(185	)	$	72
Renewable energy projects	(9		)	(2		)	36			43
Energy trading	21			11			70			67
Big 4 projects	25			26			33			37
Sunrise	—			29			9			28
Doga	—			—			11			26
Westside projects	2			1			(1		)	—
Leveraged lease income	2			1			4			4
Gain on sale of lease interest	65			—			65			—
Other projects	(1		)	—			5			10
Other operating income	(1		)	(1		)	—			1
	56			134			47			288
Corporate administrative and general	(34		)	(32		)	(104		)	(101		)
Corporate depreciation and amortization	(5		)	(6		)	(16		)	(18		)
AOI1	$	17		$	96		$	(73	)	$	169

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

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

	Three months ended September 30,					Nine months ended September 30,
(in millions)	2012			2011		2012			2011
AOI	$	17		$	96	$	(73	)	$	169
Less:
Equity in income of unconsolidated affiliates	25			56		42			68
Dividend income from projects	—			—		12			27
Production tax credits	12			10		48			47
Other income (loss), net	(1		)	—		—			6
Net (income) loss attributable to noncontrolling interests	(5		)	—		(12		)	1
Operating Income (Loss)	$	(14	)	$	30	$	(163	)	$	20

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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)	2012			2011		2012			2011
Operating Revenues	$	253		$	366	$	699		$	997
Operating Expenses
Fuel	183			157		443			390
Plant operations	73			86		302			368
Plant operating leases	19			19		56			56
Depreciation and amortization	22			29		65			87
Loss on disposal and asset impairments	—			—		4			9
Administrative and general	4			6		14			17
Total operating expenses	301			297		884			927
Operating Income (Loss)	(48		)	69		(185		)	70
Other Income	—			—		—			2
AOI	$	(48	)	$	69	$	(185	)	$	72
Statistics
Generation (in GWh)	6,653			7,957		17,459			20,987

AOI from the Midwest Generation plants decreased $117 million for the third quarter of 2012 and $257 million for the nine months ended September 30, 2012 compared to the corresponding periods of 2011. The decreases in AOI were primarily attributable to lower capacity and average realized energy prices, reduced generation and higher fuel prices, partially offset by lower planned maintenance costs and lower depreciation. Reduced generation primarily resulted from lower economic dispatch.

Included in fuel costs were unrealized gains (losses) of $2 million and $(4) million during the third quarters of 2012 and 2011, respectively, and $(2) million and $(6) million for the nine months ended September 30, 2012 and 2011, respectively, due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into as economic hedges of the variable fuel price component of rail transportation costs.

Seasonality—Midwest Generation Coal Plants

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

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Renewable Energy Projects

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

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Operating Revenues	$	47		$	44		$	182		$	155
Production Tax Credits	12			10			48			47
	59			54			230			202
Operating Expenses
Plant operations	23			20			63			56
Depreciation and amortization	38			35			116			103
Administrative and general	—			1			3			3
Total operating expenses	61			56			182			162
Equity in income from unconsolidated affiliates	(2		)	(1		)	—			—
Other Income	—			—			—			2
Net Income Attributable to Noncontrolling Interests	(5		)	1			(12		)	1
AOI1	$	(9	)	$	(2	)	$	36		$	43
Statistics
Generation (in GWh)2	1,049			953			4,346			3,893

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 not consolidated by Edison International. Generation excluding unconsolidated projects was 902 GWh and 819 GWh in the third quarters of 2012 and 2011, respectively, and 3,761 GWh and 3,356 GWh in the nine months ended September 30, 2012 and 2011, respectively.

AOI from renewable energy projects decreased $7 million for both the three and nine months ended September 30, 2012 as compared to the corresponding periods of 2011. The decrease was primarily attributable to income allocated to third-party investors in Capistrano Wind Partners, partially offset by results of operations from projects that achieved commercial operations after the third quarter of 2011. For additional information, see "Edison International Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities—Projects or Entities that are Consolidated—Capistrano Wind Equity Capital."

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The following table reconciles AOI from EME's renewable energy projects to its operating income (loss) as included in EME's consolidated statements of operations:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2012			2011			2012			2011
AOI	$	(9	)	$	(2	)	$	36		$	43
Less:
Equity in income of unconsolidated affiliates	(2		)	(1		)	—			—
Production tax credits	12			10			48			47
Other income	—			—			—			2
Net income (loss) attributable to noncontrolling interests	(5		)	1			(12		)	1
Operating Income (Loss)	$	(14	)	$	(12	)	$	—		$	(7	)

Energy Trading

AOI from energy trading activities increased $10 million for the three months ended September 30, 2012 as compared to the corresponding period of 2011. The increase was mainly due to higher revenues from trading power and MISO congestion contracts.

Adjusted Operating Income from Other Projects

Doga. EME received a distribution from the Doga project of $11 million in the second quarter of 2012 compared to $26 million in the second quarter of 2011. Distributions in the second quarter of 2011 were higher due to release of funds from restricted cash once project debt obligations were repaid. AOI is recognized when cash is distributed as the Doga project is accounted for on the cost method.

Sunrise Project. AOI from the Sunrise project decreased $29 million and $19 million in the three and nine months ended September 30, 2012, respectively, compared to the corresponding periods of 2011. The decreases in AOI were due to the transition off of a long-term power purchase agreement to merchant operations. Sunrise will continue to operate as a merchant project unless a new power purchase agreement is executed. The profitability of Sunrise as a merchant generator is dependent on market prices for power and natural gas and future results may differ from historical earnings. For additional information, see "EMG: Market Risk Exposures—Commodity Price Risk."

Seasonality. EME'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 Income (Expense)

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Interest income	$	1		$	—		$	2		$	2
Interest expense, net of capitalized interest
EME debt	(65		)	(66		)	(198		)	(191		)
Nonrecourse debt	(18		)	(15		)	(55		)	(52		)
	$	(83	)	$	(81	)	$	(253	)	$	(243	)

EMG's interest expense increased $2 million and $10 million for the three and nine months ended September 30, 2012, respectively, compared to the corresponding periods of 2011. The 2012 increase in interest expense was primarily due to higher debt balances from new project financings partially offset by higher capitalized interest. Capitalized interest was

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$9 million and $4 million for the third quarter of 2012 and 2011, respectively, and $22 million and $20 million for the nine months ended September 30, 2012 and 2011, respectively. The 2012 increase in capitalized interest was due to the Walnut Creek project construction.

Income Taxes

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

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Income (loss) from continuing operations before income taxes	$	(71	)	$	7		$	(359	)	$	(117	)
Provision (benefit) for income tax benefit at federal statutory rate of 35%	$	(25	)	$	2		$	(126	)	$	(42	)
Increase (decrease) in income tax from:
State tax benefit – net of federal tax expense	25			1			8			(6		)
Tax credits, net	(12		)	(12		)	(48		)	(49		)
Property-related	(1		)	(1		)	—			(4		)
Taxes on income allocated to noncontrolling interests	(1		)	—			(5		)	(1		)
Other	(1		)	(1		)	2			—
Total income tax benefit from continuing operations	$	(15	)	$	(11	)	$	(169	)	$	(102	)
Effective tax rate	21		%	*			47		%	87		%

* Not meaningful

EMG's effective tax rates were impacted by production tax credits, estimated state income tax benefits allocated from Edison International, and taxes on income allocated to noncontrolling interests. Estimated state income tax benefits allocated from Edison International of $7 million and $5 million were recognized for the nine months ended September 30, 2012 and 2011, respectively. The benefit for state taxes was lower in 2012 due to an adjustment in state apportionment factors.

Results of Discontinued Operations

Income (loss) from discontinued operations, net of tax, was $(76) million and $15 million for the third quarters ended September 30, 2012 and 2011, respectively and $(129) million and $(3) million for the nine months ended September 30, 2012 and 2011, respectively. Discontinued operations primarily reflects the results of Homer City. The decreases in earnings reflect a pre-tax charge of $113 million ($68 million after tax) recorded in the third quarter of 2012 associated with the planned divestiture of Homer City. In addition, Homer City's earnings were impacted by lower average realized energy prices and higher coal and emission allowance costs, partially offset by lower plant maintenance costs, as compared to the corresponding periods of 2011. For additional information, see "Edison International Notes to Consolidated Financial Statements—Note 18. Discontinued Operations."

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LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

The following table summarizes available liquidity at September 30, 2012

(in millions)	Cash and Cash Equivalents
EME as a holding company	$	325
EME subsidiaries without contractual dividend restrictions
Midwest Generation	142
Other EME subsidiaries	160
EME corporate and Midwest Generation cash and cash equivalents	627
EME subsidiaries with contractual dividend restrictions
Other EME subsidiaries	71
Other EMG subsidiaries	153
Total	$	851

See "Edison International Overview—Management Overview of EMG" for a discussion of EME's liquidity.

EME's approach to trading and risk management depends, in part, on the ability to use clearing brokers to enter into market transactions. As a result of its financial position, EME has limited access to enter into such transactions and has been subject to increased initial collateral and margin requirements. There is no assurance that EME will continue to be able to utilize clearing brokers. If EME becomes unable to utilize clearing brokers, it may seek to execute bilateral transactions with third parties which could be unavailable on commercially reasonable terms or at all.

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 and tax benefits received under a tax-allocation agreement with Edison International 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, including the current restrictions on distributions from the Homer City facility, see "—Debt Covenants and Dividend Restrictions."

Capital Investment Plan

Forecasted capital expenditures through 2014 by EME's subsidiaries for existing projects and corporate activities are as follows:

(in millions)	October through December 2012			2013		2014
Midwest Generation Plants
Environmental1		$	12	$	112	$	311
Plant capital		1		50		16
Walnut Creek Project		62		63		—
Renewable Energy Projects		50		1		2
Other capital		6		19		15
Total		$	131	$	245	$	344

¹  For additional information, see "Edison International Overview—Management Overview of EMG—Midwest Generation Environmental Compliance Plans and Costs."

Midwest Generation Capital Expenditures

Midwest Generation plants' forecasted environmental expenditures are based on retrofitting Powerton Units 5 and 6, Joliet Units 7 and 8 and Will County Units 3 and 4, using dry scrubbing with sodium-based sorbents and upgrading particulate removal systems to comply with CPS requirements for SO₂ emissions and the US EPA's regulation on hazardous air pollutant emissions. Apart from the Fisk and Crawford Stations, which ceased operations in September 2012, decisions regarding

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whether or not to proceed with retrofitting any particular remaining units to comply with CPS requirements for SO₂ emissions, including those that have received permits, are subject to a number of factors, such as market conditions, regulatory and legislative developments, liquidity and forecasted commodity prices and capital and operating costs 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 will be made as required, subject to the requirements of the CPS and other applicable regulations. Furthermore, the timing of commencing capital projects may vary from the amounts set forth in the above table. For additional discussion, see "Edison International Overview—Management Overview of EMG—Midwest Generation Environmental Compliance Plans and Costs."

Plant capital expenditures for Midwest Generation includes capital projects for boiler and turbine controls, major boiler components and electrical systems.

Historical Segment Cash Flows

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

	Nine months ended September 30,
(in millions)	2012			2011
Operating cash flows from continuing operations	$	(545	)	$	578
Operating cash flows from discontinued operations	(5		)	(14		)
Net cash provided (used) by operating activities	(550		)	564
Net cash provided by financing activities from continuing operations	348			112
Investing cash flows from continuing operations	(234		)	(488		)
Investing cash flows from discontinued operations	(19		)	(10		)
Net cash used by investing activities	(253		)	(498		)
Net increase (decrease) in cash and cash equivalents from continuing operations	$	(431	)	$	202
Net decrease in cash and cash equivalents from discontinued operations	$	(24	)	$	(24	)

Net Cash Provided (Used) by Operating Activities

The decrease in cash provided by operating activities from continuing operations in 2012 as compared to 2011 was primarily attributable to decreased operating income due to declining energy prices, increased operating costs and higher interest payments due to new energy project financings. The decrease was also attributable to EME tax-allocation payments made, net of receipts, of $168 million in 2012 compared to tax-allocation payments received, net of payments made, of $182 million in 2011. Operating cash flow was also impacted by timing of cash receipts and disbursements related to working capital items.

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Net Cash Provided by Financing Activities

The change in financing activities is primarily due to cash contributions from noncontrolling interests and the timing of financings and repayment of debt as summarized in the following table:

	Nine months ended September 30,
(in millions)	2012			2011
Cash contributions from noncontrolling interests	$	238		$	—
Long-term debt financings
Renewable energy projects	—			76
Walnut Creek project	154			92
Short-term debt financings
Renewable energy projects	21			32
Debt repayments
Renewable energy projects	(23		)	(78		)
Other projects	(8		)	(7		)
Financing costs and others	(34		)	(3		)
Total cash provided by financing activities	$	348		$	112

Net Cash Used by Investing Activities

The change in investing activities is primarily due to the timing of capital expenditures and cash collateral to secure letter of credit facilities associated with the termination of EME's revolving credit facility. Changes in other investing activities are reflected in the following table:

	Nine months ended September 30,
(in millions)	2012			2011
Capital expenditures
Midwest Generation plants
Environmental	$	(17	)	$	(71	)
Plant capital	(7		)	(6		)
Homer City plant
Environmental	(8		)	—
Plant capital	(11		)	(10		)
Walnut Creek project	(159		)	(166		)
Renewable energy projects	(78		)	(195		)
Other capital expenditures	(5		)	(8		)
Proceeds from sale of lease interest, net	107			—
Investments in other assets	(9		)	(29		)
Collateral for letter of credit facilities	(51		)	—
Other investing activities	(15		)	(13		)
Total cash used in investing activities	$	(253	)	$	(498	)

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Credit Ratings

Credit ratings for EME and EMMT as of September 30, 2012 were as follows:

	Moody's Rating	S&P Rating	Fitch Rating
EME1	Ca	CCC	C
EMMT	Not Rated	CCC	Not Rated

¹  Senior unsecured 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.

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

Hedging Activities

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. 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, 2012, 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 as of September 30, 2012 could increase by approximately $26 million over the remaining life of the contracts using a 95% confidence level.

Intercompany Tax-Allocation Agreement

EMG and its subsidiaries, EME and Edison Capital, are included in the consolidated federal and combined state income tax returns of Edison International and are eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of EME and Edison Capital to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME and Edison Capital in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EMG's subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EMG receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize EMG's consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, EMG is obligated during periods it generates taxable income to make payments under the tax-allocation agreements. Tax-allocation receipts and payments may also be affected by redetermination of utilization of net operating losses resulting from carryback of net operating losses on a consolidated basis or settlement of tax liabilities for prior periods. In September 2012, EME made a tax-allocation payment to Edison International of approximately $185 million related to the displacement, under the tax-allocation agreement, of tax benefits previously received for 2009 federal income taxes. Edison International expects to pay federal and state tax-allocation payments to EME during the next six months of approximately $160 million related to 2012 income taxes. The timing of the receipt of or payment of funds due under the tax-allocation agreement is dependent on future taxable income of Edison International. Estimates of future taxable income are uncertain and changes in estimates may have a material impact on the consolidated financial statements.

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Debt Covenants and Dividend Restrictions

For a description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "Debt Covenants and Dividend Restrictions " in the year-ended 2011 MD&A. Upon the expiration of the Midwest Generation credit facility on June 29, 2012, the debt-to-capitalization ratio as discussed in the Form 10-K is no longer required and Midwest Generation is also no longer contractually restricted in its ability to make distributions to EME. For further information, see "—Available Liquidity." Homer City is restricted from making distributions.

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, 2012, the maximum permissible sale or disposition of EME's assets was $727 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.

Contractual Obligations and Contingencies

Contractual Obligations

Big Sky Turbine Financing

For a discussion of Big Sky Turbine Financing, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Big Sky Turbine Financing."

Coal Transportation Agreements

For a discussion of Midwest Generation's coal transportation agreements, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Coal Transportation Agreements."

Capital Commitments

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

Contingencies

EMEhas contingenciesrelated to the Midwest Generation New Source Review and other litigation, Homer City New Source Review and other litigation, and environmental remediation which are discussed in "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies."

Off-Balance Sheet Transactions

For a discussion of EME's off-balance sheet transactions, refer to "EMG: Liquidity and Capital Resources—Off-Balance Sheet Transactions" in the year-ended 2011 MD&A. There have been no significant developments with respect to off-balance sheet transactions that affect disclosures presented in the 2011 Form 10-K except as set forth in "Edison International Overview—Management Overview of EMG—Homer City Lease."

Environmental Matters and Regulations

For a discussion of EMG's environmental matters, refer to "Environmental Regulation of Edison International and Subsidiaries" in Item 1 of Edison International's 2011 Form 10-K. There have been no significant developments with respect to environmental matters specifically affecting EMG since the filing of the 2011 Form 10-K, except as set forth in "Edison International Notes to Consolidated Financial Statements—Note 10. Environmental Developments."

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MARKET RISK EXPOSURES

For a detailed discussion of market risk exposures, including commodity price risk, credit risk and interest rate risk, refer to "EMG: Market Risk Exposures" in the year-ended 2011 MD&A.

Derivative Instruments

Fair Value Disclosures

In determining the fair value of EME's derivative positions, EME uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EME'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. Energy from 428 MW of merchant renewable energy projects is sold in the energy markets, primarily at spot prices in PJM and ERCOT.

The following table depicts the average historical market prices for energy per megawatt-hour at the Northern Illinois Hub related to the Midwest Generation plants for the first nine months of 2012 and 2011:

	24-Hour Average Historical Market Prices1
	2012		2011
Northern Illinois Hub	$	28.56	$	35.30

¹  Energy prices were calculated at the Northern Illinois Hub using historical hourly day-ahead prices as published by PJM or provided on the PJM web-site.

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at September 30, 2012:

	24-Hour Forward Energy Prices1
	Northern Illinois Hub
2012
October		$	27.35
November		27.17
December		30.22
2013 calendar "strip"2		$	30.60
2014 calendar "strip"2		$	31.31

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

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

Power prices remained low in the first nine months of 2012 due to an abundance of low-priced natural gas and the sales volume from the Midwest Generation plants has been correspondingly affected. Forward market prices at the Northern Illinois 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 Midwest Generation plants into these markets may vary materially from the forward market prices set forth in the preceding table.

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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 at September 30, 2012 for electricity expected to be generated during the remainder of 2012 and in 2013:

	2012			2013
	MWh (in thousands)	Average price/ MWh1		MWh (in thousands)	Average price/ MWh1
Midwest Generation plants2	2,028	$	37.53	3,615	$	36.55

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 prices set forth above.

²  Includes hedging transactions primarily at the Northern Illinois Hub and to a lesser extent the AEP/Dayton Hub, both in PJM, and the Indiana Hub in MISO.

Sunrise Project

Beginning July 1, 2012, EME's 50% owned Sunrise project, which EME accounts for on the equity method, will operate as a merchant generator and sell power at spot prices from its 572 MW facility into the California ISO market, unless a power purchase agreement is obtained. Spot prices are currently expected to be between the price for the NP15 and SP15 trading locations in that market. As a gas-fired merchant generator, Sunrise purchases natural gas based on spot prices and, accordingly, the plant is dispatched in periods when the power prices exceed the cost of fuel and other variable operations and maintenance costs. Historically, Sunrise has operated more during the summer months due to higher demand driven by warm weather.

Capacity Price Risk

Under the RPM, capacity commitments are made in advance to provide a long-term pricing signal for construction and maintenance of capacity resources. The following table summarizes the status of capacity sales for Midwest Generation at September 30, 2012:

	RPM Capacity Sold in Base Residual Auction			Other Capacity Purchases, Net of Sales1				Aggregate Average Price per MW-day
	MW	Price per MW-day		MW		Average Price per MW-day
October 1, 2012 to May 31, 2013	4,704	$	16.46	(450	)	$	15.67	$	16.54
June 1, 2013 to May 31, 2014	4,650	27.73		(2,430	)	7.01		50.40
June 1, 2014 to May 31, 2015	4,625	125.99		(700	)	5.54		147.47
June 1, 2015 to May 31, 2016	3,620	136.00		—		—		136.00

¹  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.

The RPM auction capacity prices for the delivery period of October 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 capacity prices in other areas.

Revenues from the sale of capacity from Midwest Generation beyond the periods set forth above will depend upon the amount of capacity available and future market prices either in PJM or nearby markets if those facilities have an opportunity to capture a higher value associated with those markets.

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Basis Risk

During the nine months ended September 30, 2012, day-ahead prices at the individual busbars of the Midwest Generation plants compared to the AEP/Dayton Hub, Indiana Hub (Cinergy Hub) and Northern Illinois Hub were on average lower by 6%, lower by 1% and higher by 1%, respectively. During the nine months ended September 30, 2011, day-ahead prices at the individual busbars of the Midwest Generation plants were lower compared to the AEP/Dayton Hub and Indiana Hub (Cinergy Hub) by an average of 12% and 2%, respectively. Differences in day-ahead pricing between the individual busbars of the Midwest Generation plants generally arise due to transmission congestion.

Coal Price Risk

The Midwest Generation plants purchase coal primarily from the Southern PRB of Wyoming. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at September 30, 2012, for the remainder of 2012 and the following two years:

	October through December 2012		2013	2014
Amount of Coal Under Contract in Millions of       Equivalent Tons1		4.9	11.1	9.8

¹  The amount of coal under contract in equivalent tons is calculated based on contracted tons and applying an 8,800 Btu equivalent.

Midwest Generation is subject to price risk for purchases of coal that are not under contract. Market prices of PRB coal based on 8,800 Btu per pound heat content and 0.8 pounds of SO₂ per MMBtu sulfur content decreased to a price of $9.20 per ton at September 28, 2012, compared to a price of $12.75 per ton at December 30, 2011, as reported by the EIA.

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. EME'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, 2012, the balance sheet exposure as described above, by the credit ratings of EME's counterparties, was as follows:

	September 30, 2012
(in millions)	Exposure2		Collateral			Net Exposure
Credit Rating1
A or higher	$	91	$	—		$	91
A-	8		(8		)	—
BBB+	4		—			4
BBB	—		—			—
BBB-	—		—			—
Below investment grade	29		(29		)	—
Total	$	132	$	(37	)	$	95

¹  EME 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 $64 million of net accounts receivable and payables and $68 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, EME's subsidiaries have posted a $79 million cash margin in the aggregate with PJM, NYISO,

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MISO, clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.

The Midwest Generation 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 73% of EME's consolidated operating revenues for the nine months ended September 30, 2012. At September 30, 2012, EME's account receivable due from PJM was $53 million.

EME's 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. EME'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 EME's turbine suppliers may have a material impact on EME's projects and development efforts. Two of EME's wind turbine suppliers, Suzlon and Clipper, are currently experiencing significant adverse credit and liquidity issues. As a result, EME's ability to enforce performance and warranty guarantees is subject to the credit risk of these counterparties.

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME 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 further details, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements" and "—Note 6. Derivative Instruments and Hedging Activities."

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EDISON INTERNATIONAL PARENT AND OTHER

RESULTS OF OPERATIONS

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

Edison International Parent and Other loss from continuing operations was $36 million and $13 million for the three- and nine-month periods ended September 30, 2012, respectively, compared to $48 million and $19 million for the same periods in 2011. In the third quarter of 2012, Edison International and EME recorded income tax charges of $13 million and $16 million, respectively, related to changes in California apportionment rates used in prior periods. The charges related to an update of Edison International's assessment of uncertain tax positions following a recent court case. In addition, Edison International updated its estimated long-term California apportionment rate applicable to consolidated deferred income taxes as a result of reductions in EME's projected sales resulting in income charges during the third quarter of $16 million.

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.

During the second quarter of 2012, Edison International Parent replaced its credit facilities with a new $1.25 billion five-year revolving credit facility that matures May 2017. The following table summarizes the status of the Edison International Parent credit facility at September 30, 2012:

(in millions)	Edison International (parent)
Commitment	$	1,250
Outstanding borrowings	(28		)
Amount available	$	1,222

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. The ratio of debt to total capitalization is defined in the credit agreement and generally excludes the consolidated debt and total capital of EME. At September 30, 2012, Edison International's consolidated debt to total capitalization ratio was 0.48 to 1.

Historical Segment 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)	2012		2011
Net cash provided (used) by operating activities	$	51	$	(13	)
Net cash provided by financing activities	36		21
Net cash provided by investing activities	—		1
Net increase in cash and cash equivalents	$	87	$	9

Net Cash Used by Operating Activities

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

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Net Cash Provided by Financing Activities

Financing activities for the first nine months of 2012 were as follows:

• Paid $318 million of dividends to Edison International common shareholders.

• Received $349 million of dividend payments from SCE.

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.

EDISON INTERNATIONAL (CONSOLIDATED)

LIQUIDITY AND CAPITAL RESOURCES

Contractual Obligations

Significant changes with respect to Edison International (Consolidated) contractual obligations since the filing of the 2011 Form 10-K are discussed in "EMG: Liquidity and Capital Resources—Contractual Obligations" and "SCE: Liquidity and Capital Resources—Contractual Obligation."

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 2011 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 Item 3 is included in the MD&A under the headings "SCE: Market Risk Exposures" and "EMG: Market Risk Exposures."

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 third quarter of 2012. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the third quarter of 2012, Edison International's disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in Edison International’s internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the third quarter of 2012 that have materially affected, or are reasonably likely to materially affect, Edison International’s internal control over financial reporting.

Jointly Owned Utility Plant

Edison International's scope of evaluation of internal control over financial reporting includes its Jointly Owned Utility Projects.

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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 2011 Form 10-K. There have been no significant developments with respect to legal proceedings specifically affecting Edison International since the filing of the 2011 Form 10-K, except as follows:

Midwest Generation New Source Review and Other Litigation

In February 2012, certain of the environmental action groups that had intervened in the US EPA's New Source Review case entered into an agreement with Midwest Generation to dismiss without prejudice all of their opacity claims as to all defendants. The agreed upon motion to dismiss was approved by the court on March 26, 2012.

In October 2012, Midwest Generation and the Illinois Environmental Protection Agency entered into Compliance Commitment Agreements outlining specified environmental remediation measures and groundwater monitoring activities to be undertaken at its Powerton, Joliet, Crawford, Will County and Waukegan generating stations. Also in October 2012, several environmental groups filed a complaint before the Illinois Pollution Control Board against Midwest Generation, alleging violations of the Illinois groundwater standards through the operation of coal ash disposal ponds at its Powerton, Joliet, Waukegan and Will County generating stations. The complaint requests the imposition of civil penalties, injunctive relief and remediation.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table contains information about all purchases of Edison International Common Stock made by or on behalf of Edison International in the third quarter of 2012.

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, 2012 to July 31, 2012	292,462	$	45.98	—	—
August 1, 2012 to August 31, 2012	505,430	45.23		—	—
September 1, 2012 to September 30, 2012	308,430	45.25		—	—
Total	1,106,322	45.44		—	—

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

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ITEM 6.     EXHIBITS

Exhibit Number	Description
10.1	Edison International 2008 Director Deferred Compensation Plan, as amended and restated effective October 25, 2012
10.2	Edison International 2008 Executive Deferred Compensation Plan, as amended and restated effective October 24, 2012
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, 2012, filed on November 1, 2012, 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 Consolidated Financial Statements

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) 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
		By:	/s/ Mark C. Clarke
			Mark C. Clarke Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)
Date:	November 1, 2012

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EX-10.1

Exhibit 10.1

EDISON INTERNATIONAL

2008 DIRECTOR DEFERRED COMPENSATION PLAN

Amended and Restated Effective

October 25, 2012

	TABLE OF CONTENTS
		Page
ARTICLE 1 DEFINITIONS		1
ARTICLE 2 DEFERRAL ELECTIONS		2
	2.1 Elections	3
	2.2 Vesting	4
ARTICLE 3 DEFERRAL ACCOUNTS		4
	3.1 Deferral Accounts	4
	3.2 Timing of Credits	4
	3.3 Statement of Accounts	5
ARTICLE 4 PAYMENT ELECTIONS		5
	4.1 Primary Payment Election	5
	4.2 Contingent Payment Election	6
	4.3 Changes to Payment Elections	6
	4.4 Small Benefit Exception	7
	4.5 Six-Month Delay in Payment for Specified Employees	7
	4.6 Conflict of Interest Exception, Etc.	7
ARTICLE 5 SURVIVOR BENEFITS		7
	5.1 Payment	7
	5.2 Special Increase	7
ARTICLE 6 BENEFICIARY DESIGNATION		8
ARTICLE 7 CONDITIONS RELATED TO BENEFITS		8
	7.1 Nonassignability	8
	7.2 Unforeseeable Emergency Distribution	9
	7.3 No Right to Assets	9
	7.4 Protective Provisions	9
	7.5 Constructive Receipt	9
	7.6 Withholding	9
	7.7 Incapacity	10
ARTICLE 8 PLAN ADMINISTRATION		10
	8.1 Plan Interpretation	10
	8.2 Limited Liability	10

	TABLE OF CONTENTS
		Page
ARTICLE 9 AMENDMENT OR TERMINATION OF PLAN		10
	9.1 Amendment of Plan	10
	9.2 Termination of Plan	10
	9.3 Amendment or Termination after Change in Control	11
	9.4 Exercise of Power to Amend or Terminate	11
ARTICLE 10 CLAIMS AND REVIEW PROCEDURES		11
	10.1 Claims Procedure	11
	10.2 Dispute Arbitration	12
ARTICLE 11 MISCELLANEOUS		13
	11.1 Successors	13
	11.2 Trust	13
	11.3 Service Not Guaranteed	13
	11.4 Gender, Singular and Plural	13
	11.5 Captions	13
	11.6 Validity	13
	11.7 Waiver of Breach	14
	11.8 Applicable Law	14
	11.9 Notice	14
	11.10 Statutes and Regulations	14

ii

EDISON INTERNATIONAL

2008 DIRECTOR DEFERRED COMPENSATION PLAN

Amended and Restated Effective October 25, 2012

PREAMBLE

The purpose of this Plan is to provide Eligible Directors of participating Affiliates with the opportunity to defer payment and taxation of some elements of their compensation.

This Plan applies to amounts arising from board compensation earned after December 31, 2004, and is intended to comply with Section 409A of the Internal Revenue Code and the regulations issued thereunder. This version of the Plan applies to amounts arising from deferrals of compensation pursuant to deferral elections made on or after December 1, 2012. For the terms and conditions applicable to amounts deferred under this Plan pursuant to deferral elections made prior to that date, refer to the version of this Plan as in effect at the time of the applicable deferral election.

ARTICLE 1

DEFINITIONS

Capitalized terms in the text of the Plan are defined as follows:

Administrator means the Compensation and Executive Personnel Committee of the Board of Directors of EIX.

Affiliate means EIX or any corporation or entity which (i) along with EIX, is a component member of a "controlled group of corporations" within the meaning of Section 414(b) of the Code, and (ii) has approved the participation of its directors in the Plan.

Beneficiary means the person or persons or entity designated as such in accordance with Article 6 of the Plan.

Board means the Board of Directors of EIX.

Code means the Internal Revenue Code of 1986, as amended.

Company means the Affiliate the Participant serves as a director.

Contingent Event means the Participant's Disability or death while serving on an Affiliate board or Separation from Service for other reasons if such event occurs prior to the Participant's Retirement.

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Contingent Payment Election means an election regarding the time and form of payment made or deemed made in accordance with Section 4.2.

Crediting Rate means the rate at which interest will be credited to Deferral Accounts. The rate will be determined annually in advance of the calendar year and will be equal to the average monthly Moody's Corporate Bond Yield for Baa Public Utility Bonds for the 60 months preceding November 1st of the prior year. EIX reserves the right to prospectively change the definition of Crediting Rate.

Deferral Account means the notional account established for record keeping purposes for a Participant pursuant to Article 3 of the Plan.

Deferral Election means the Participant's written election to defer amounts under the Plan, submitted to the Administrator in the manner prescribed by the Administrator.

Deferral Period means the Plan Year covered by a valid Deferral Election previously submitted by a Participant, or in the case of a newly eligible Participant, the balance of the Plan Year following the date of the Deferral Election.

Deferred Stock Unit means a bookkeeping entry linked to shares of EIX Common Stock on a one-for-one basis. Deferred Stock Units may be credited to a Participant's Deferral Account as a result of an award under the Equity Compensation Plan, 2007 Performance Incentive Plan or any successor plan or Dividend Equivalents on such an award. Deferred Stock Units will be payable in shares of EIX Common Stock on a one-for-one basis, or to the extent determined by the Board in the terms applicable to a particular Deferred Stock Unit award, in cash equal to the value of such shares of EIX Common Stock.

Disability means the Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve months.

Dividend Equivalent means an amount equal to the dividend declared by the Board on one share of EIX common stock for any calendar quarter.

EIX means Edison International.

Eligible Director means a non-employee director of an Affiliate who (i) is a U.S. director or an expatriate who is based and paid in the U.S., and (ii) is designated by the Company as eligible to participate in the Plan (subject to the restrictions in Section 7.2 of the Plan).

Participant means an Eligible Director who has completed a Deferral Election with respect to future payments pursuant to Article 2 of the Plan, or a director or former director who has a Deferral Account balance.

2

Payment Election means a Primary Payment Election or a Contingent Payment Election.

Plan means the EIX 2008 Director Deferred Compensation Plan.

Plan Year means the calendar year.

Primary Payment Election means an election regarding the time and form of payments made or deemed made in accordance with Section 4.1.

Retainers and Fees means retainers and meeting fees which would be paid to a Participant as an Eligible Director for the Plan Year before reductions for deferrals under the Plan.

Retirement means a Separation from Service after attaining age 55 with at least 5 years of board service.

Separation from Service occurs when a Participant dies, retires, or otherwise has a termination of service from all Affiliate boards of directors that constitutes a “separation from service” within the meaning of Treasury Regulation Section 1.409A-1(h), without regard to the optional alternative definitions available thereunder.

Similar Plan means a plan required to be aggregated with this Plan under Treasury Regulation Section 1.409A-1(c)(2)(i).

Termination of Service means the voluntary or involuntary Separation from Service for any reason other than Retirement or death.

Unforeseeable Emergency means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant's Beneficiary, or the Participant's spouse or dependent (as defined in Code Section 152, without regard to Sections 152(b)(1), (b)(2) and (d)(1)(B)); loss of the Participant's property due to casualty (including the need to rebuild a home following damage to a home not otherwise covered by insurance, for example, not as a result of a natural disaster); or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the Participant's control.

Valuation Date means the last day of the month in which the final day of board service falls prior to Separation from Service, unless distribution is scheduled or required to commence on a date other than the first day of the month following Separation from Service, in which latter case Valuation Date means the day before a distribution is scheduled or required to commence.

ARTICLE 2

DEFERRAL ELECTIONS

2.1 Elections

(a)    Retainers and Fees. An Eligible Director may elect to participate in the Plan and defer Retainers and Fees by submitting a Deferral Election to the Administrator specifying the whole percentage of Retainers and Fees to be deferred prior to the beginning of the Plan Year during

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which the Eligible Director performs the services for which such Retainers and Fees are to be earned. Notwithstanding the foregoing, an individual who first becomes an Eligible Director during a Plan Year may make an initial Deferral Election for deferral of Retainers and Fees under this Plan within thirty days after the date the individual becomes an Eligible Director, provided that such Eligible Director has not previously become eligible to participate in this or any Similar Plan. Any such election will apply to Retainers and Fees earned for services performed after the election is submitted to the Administrator. Once made, a Deferral Election (including any election regarding time and form of payment) will continue to apply for subsequent Deferral Periods unless (i) the Eligible Director submits a new Deferral Election during a subsequent enrollment period changing the deferral amount or revoking the existing election, or (ii) the Participant is not an Eligible Director on the last day of a subsequent enrollment period.

(b)    Deferred Stock Units. If upon initial election to the Board, an Eligible Director receives an award of Deferred Stock Units made under the 2007 Performance Incentive Plan or any successor plan, such Deferred Stock Units shall be credited to this Plan. An Eligible Director may elect to receive Deferred Stock Units rather than shares of Common Stock upon board re-election by submitting a Deferral Election to the Administrator prior to the beginning of the Plan Year in which re-election occurs. Once made, a Deferral Election (including any election regarding time and form of payment) will continue to apply for subsequent Deferral Periods unless (i) the Eligible Director submits a new Deferral Election during a subsequent enrollment period changing the deferral percentage or revoking the existing election or (ii) the Participant is not an Eligible Director on the last day of a subsequent enrollment period.

2.2 Vesting

Amounts deferred under this Article 2 and any earnings thereon will be 100% vested at all times.

ARTICLE 3

DEFERRAL ACCOUNTS

3.1 Deferral Accounts

Solely for record keeping purposes, the Administrator will maintain a Deferral Account for each Participant with such subaccounts as the Administrator or its record keeper finds necessary or convenient in the administration of the Plan.

3.2 Timing of Credits

(a)    Retainer and Fee Deferrals.The Administrator will credit to the Participant's Deferral Account the Retainer and Fee Deferrals at the time such amounts would otherwise have been paid to the Participant but for the Deferral Election.

(b)    Deferred Stock Units. The Administrator will credit Deferred Stock Units to the Participant's Deferral Account as of the effective date of any award of Deferred Stock Units under the 2007 Performance Incentive Plan or any successor plan.

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(c)    Earnings Crediting Dates.

(i)    The Administrator will credit interest at the Crediting Rate to the Participant's Deferral Account on a daily basis, compounded annually.

(ii)    The Administrator will credit a Dividend Equivalent for each Deferred Stock Unit credited to the Participant's Deferral Account on the EIX common stock ex-dividend date each quarter. Dividend Equivalents so credited will be converted into additional Deferred Stock Units based on the closing price of EIX Common Stock on that date as reported by Bloomberg Professional Service. Fractional Dividend Equivalents and Deferred Stock Units will be credited.

3.3 Statement of Accounts

The Administrator will periodically either provide or make available to each Participant a statement setting forth the balance of the Deferral Account maintained for the Participant.

ARTICLE 4

PAYMENT ELECTIONS

4.1 Primary Payment Election

As part of a Deferral Election, a Participant may make a Primary Payment Election specifying the payment schedule for each subaccount that will be created as a result of the Deferral Election. The choices available for a Primary Payment Election are as follows:

(a)    Monthly installments for 60 to 180 months; or

(b)    A single lump sum; or

(c)    Two to fifteen installments paid annually; or

(d)    Any combination of the preceding three choices.

Payments under this Primary Payment Election may commence upon (i) the first day of a specified month and year that may be no later than the month and year in which the Participant attains age 75; (ii) the Participant's Retirement; or (iii) the first day of the month that is a specified number of months following the Participant's Retirement or the first day of a specified month a specified number of years following the calendar year in which Retirement occurs (provided that if the date otherwise determined pursuant to this clause (iii) is later than the month and year in which the Participant attains age 75, the date pursuant to this clause (iii) shall be the later of the Participant's Retirement or the month and year in which the Participant attains age 75).

Subject to Section 4.5, lump sum payments or initial installment payments will be made within 60 days of the scheduled dates. Interest will be added to the payment amount for the days elapsed between the scheduled payment date and the actual date of payment.

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If paid in installments of cash, the installments will be paid in amounts that will amortize the Deferral Account or subaccount balance with interest credited at the Crediting Rate over the period of time benefits are to be paid. For purposes of calculating installments, the Deferral Account or subaccount will be valued as of December 31 each year, and the subsequent installments will be adjusted for the next calendar year according to procedures established by the Administrator. Notwithstanding anything herein to the contrary, distribution in installments shall be treated as a single payment as of the date of the initial installment for purposes of Section 409A of the Code. If paid in monthly installments, the installments may be paid in a single check each month or in more than one check for any given month, provided that in either such case the total amount of the monthly payment shall not change.

If no Primary Payment Election has been made, the Primary Payment Election shall be deemed to be a single lump sum upon the Participant's Retirement (or, if earlier, the Participant's death or Disability).

4.2 Contingent Payment Election

As part of a Deferral Election, a Participant may make a Contingent Payment Election for each of the Contingent Events of (1) the Participant's death during service on an Affiliate board, (2) the Participant's Disability during service on an Affiliate board and (3) Termination of Service, for each subaccount that will be created as a result of the Deferral Election, which Contingent Payment Election will take effect upon the first Contingent Event, if any, that occurs before the Participant's Retirement (if the Participant specified a payment schedule determined by reference to Retirement in Section 4.1) or the first day of a specified month and year elected by the Participant pursuant to Section 4.1. The choices available for the Contingent Payment Election are those specified in Section 4.1 except that the references to Retirement shall instead refer to the applicable Contingent Event.

If the Participant has made no Contingent Payment Election and a Contingent Event occurs prior to Retirement (if the Participant specified a payment schedule determined by reference to Retirement in Section 4.1) or the first day of a specified month and year elected by the Participant pursuant to Section 4.1, the Administrator will pay the benefit as specified in the Participant's Primary Payment Election, except that payments scheduled for payment or commencement of payment “upon Retirement,” or with a payment date determined by reference to “Retirement,” will be paid, commence or have payment determined by reference to the first day of the month following the month in which the Contingent Event occurs. If the Participant has made neither a Contingent Payment Election nor a Primary Payment Election and a Contingent Event occurs prior to Retirement, the Payment Election shall be deemed to be a single lump sum upon the Participant's Contingent Event.

4.3 Changes to Payment Elections

Participants may change a Primary Payment Election or Contingent Payment Election, including a deemed Payment Election, after the period allowed for the initial Deferral Election by submitting a new written Payment Election to the Administrator in the manner prescribed by the Administrator, subject to the following conditions: (1) the new Payment Election shall not be effective unless made at least twelve months before the payment or commencement date

6

scheduled under the prior Payment Election; (2) the new Payment Election must defer a lump sum payment or commencement of installment payments for a period of at least five years from the date that the lump sum would have been paid or installment payments would have commenced under the prior Payment Election and (3) the election shall not be effective until twelve months after it is submitted to the Administrator. If at the time a new Payment Election is submitted, the Administrator determines that imposition of the five-year delay would require that a Participant's payments begin after he or she has attained age 75, then the Participant will not be permitted to make a new Payment Election. The payment schedules available under a new Payment Election are those specified in Section 4.1 and 4.2 (as applicable), subject to the conditions specified in this paragraph.

4.4 Small Benefit Exception

Notwithstanding the foregoing, the Administrator may, in its sole discretion and as determined by it in writing, pay the benefits in a single lump sum if the sum of all benefits payable to the Participant under this Plan and all Similar Plans is less than or equal to the applicable dollar amount under Section 402(g)(1)(B) of the Code.

4.5 Six-Month Delay in Payment for Specified Employees

Notwithstanding any provision of this Plan to the contrary, if a Participant is reasonably determined to be a “specified employee” as defined in Code Section 409A and is entitled to a distribution from the Plan due to the Participant's Separation from Service, the lump sum payment or the commencement of installment payments, as the case may be, may not be scheduled to occur or occur before the date that is the earlier of (1) six months following the Participant's Separation from Service for reasons other than death or (2) the Participant's death.

4.6 Conflict of Interest Exception, Etc.

Notwithstanding the foregoing, the Administrator may, in its sole discretion, pay benefits in a single lump sum if permitted under Treasury Regulation Section 1.409A-3(j)(4)(iii). In addition, the Administrator may, in its sole discretion, accelerate benefits if and to the extent permitted under any of the other exceptions specified in Treasury Regulation Section 1.409A-3(j)(4) to the general rule in Code Section 409A prohibiting accelerated payments, provided that the terms of Section 4.4 of the Plan shall govern whether benefits will be paid in a single lump sum pursuant to the small benefit exception contained in Treasury Regulation Section 1.409A-3(j)(4)(v).

ARTICLE 5

SURVIVOR BENEFITS

5.1 Payment

Following the Participant's death, payment of the Participant's Deferral Account will be made to the Participant's Beneficiary or Beneficiaries according to the payment schedule elected or deemed elected according to Article 4.

5.2 Special Increase

This Section 5.2 applies as to any Participant who was first an Eligible Director in this Plan on or before December 31, 2008. If any such Participant's death occurs within the first ten years

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following the date on which he or she was first an Eligible Director, the balance existing on the date of the Participant's death, but excluding the portion of the balance derived from Deferred Stock Units and from Dividend Equivalents associated with stock options, shall be doubled. The doubled balance will be paid out according to the payment schedule elected or deemed elected according to Article 4. For the avoidance of doubt, the death benefit provided in this Section 5.2 is intended as a separate plan within the meaning of Code Section 409A and Treasury Regulation Section 1.409A-1(c).

ARTICLE 6

BENEFICIARY DESIGNATION

The Participant will have the right, at any time, to designate any person or persons or entity as Beneficiary (both primary and contingent) to whom payment under the Plan will be made in the event of the Participant's death. The Beneficiary designation will be effective when it is submitted to the Administrator during the Participant's lifetime in accordance with procedures established by the Administrator.

The submission of a new Beneficiary designation will cancel all prior Beneficiary designations. Any finalized divorce or marriage of a Participant subsequent to the date of a Beneficiary designation will revoke such designation, unless in the case of divorce the previous spouse was not designated as a Beneficiary, and unless in the case of marriage the Participant's new spouse has previously been designated as Beneficiary. The spouse of a married Participant must consent in writing to any designation of a Beneficiary other than the spouse.

If a Participant fails to designate a Beneficiary as provided above, or if the Beneficiary designation is revoked by marriage, divorce, or otherwise without execution of a new designation, or if every person designated as Beneficiary predeceases the Participant, then the Administrator will direct the distribution of the benefits to the Participant's estate. If a primary Beneficiary dies after the Participant's death but prior to completion of benefits under this Plan and no contingent Beneficiary has been designated by the Participant, any remaining payments will be paid to the primary Beneficiary's Beneficiary, if one has been designated, or to the Beneficiary's estate.

ARTICLE 7

CONDITIONS RELATED TO BENEFITS

7.1 Nonassignability

The benefits provided under the Plan may not be alienated, assigned, transferred, pledged or hypothecated by or to any person or entity, at any time or any manner whatsoever. These benefits will be exempt from the claims of creditors of any Participant or other claimants and from all orders, decrees, levies, garnishment or executions against any Participant to the fullest extent allowed by law. Notwithstanding the foregoing, the benefit payable to a Participant may be assigned in full or in part, pursuant to a domestic relations order of a court of competent jurisdiction.

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7.2 Unforeseeable Emergency Distribution

A Participant may submit a hardship distribution request to the Administrator in writing setting forth the reasons for the request. The Administrator will have the sole authority to approve or deny such requests. Upon a finding that the Participant has suffered an Unforeseeable Emergency, the Administrator may in its discretion, permit the Participant to cease any on-going deferrals and accelerate distributions of benefits under the Plan in the amount reasonably necessary to alleviate the Unforeseeable Emergency. If a distribution is to be made to a Participant on account of an Unforeseeable Emergency, the Participant may not make deferrals under the Plan until one entire Plan Year following the Plan Year in which a distribution based on an Unforeseeable Emergency was made has elapsed.

7.3 No Right to Assets

The benefits paid under the Plan will be paid from the general funds of the Company, and the Participant and any Beneficiary will be no more than unsecured general creditors of the Company with no special or prior right to any assets of the Company for payment of any obligations hereunder. Neither the Participant nor the Beneficiary will have a claim to benefits from any other Affiliate. Amounts of compensation deferred by Participants pursuant to this Plan accrue as liabilities of the participating Affiliate at the time of the deferral under the terms and conditions set forth herein. By electing to defer compensation under the Plan, Participants consent to EIX sponsorship of the Plan, but acknowledge that EIX is not a guarantor of the benefit obligations of other participating Affiliates. Each participating Affiliate is responsible for payment of the accrued benefits under the Plan with respect to its own Eligible Directors subject to the terms and conditions set forth herein.

7.4 Protective Provisions

The Participant will cooperate with the Administrator by furnishing any and all information requested by the Administrator, in order to facilitate the payment of benefits hereunder, taking such physical examinations as the Administrator may deem necessary and signing such consents to insure or taking such other actions as may be requested by the Administrator. If the Participant refuses to cooperate, the Administrator and the Company will have no further obligation to the Participant under the Plan.

7.5 Constructive Receipt

Notwithstanding anything to the contrary in this Plan, in the event the Administrator determines that amounts deferred under the Plan have failed to comply with Section 409A and must be recognized as income for federal income tax purposes, distribution of the amounts included in a Participant's income will be made to such Participant. The determination of the Administrator under this Section 7.5 will be binding and conclusive.

7.6 Withholding

The Participant or the Beneficiary will make appropriate arrangements with the Administrator for satisfaction of any federal, state or local income tax withholding requirements and Social Security or other director tax requirements applicable to the payment of benefits under the Plan.

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If no other arrangements are made, the Administrator may provide, at its discretion, for such withholding and tax payments as may be required.

7.7 Incapacity

If any person entitled to payments under this Plan is incapacitated and unable to use such payments in his or her own best interest, EIX may direct that payments (or any portion) be made to that person's legal guardian or conservator, or that person's spouse, as an alternative to payment to the person unable to use the payments. EIX will have no obligation to supervise the use of such payments, and court-appointed guardianship or conservatorship may be required.

ARTICLE 8

PLAN ADMINISTRATION

8.1 Plan Interpretation

The Administrator will administer the Plan and interpret, construe and apply its provisions in accordance with its terms and will provide direction and oversight as necessary to management, staff, or contractors to whom day-to-day Plan operations may be delegated. The Administrator will establish, adopt or revise such rules and regulations as it may deem necessary or advisable for the administration of the Plan. The Administrator will interpret and construe the Plan and the prior version of the Plan to comply with Section 409A of the Code. All decisions of the Administrator will be final and binding.

8.2 Limited Liability

Neither the Administrator, nor any of its members or designees, will be liable to any person for any action taken or omitted in connection with the interpretation and administration of this Plan.

ARTICLE 9

AMENDMENT OR TERMINATION OF PLAN

9.1 Amendment of Plan

Subject to the terms of Section 9.3, EIX may at any time amend the Plan in whole or in part, provided, however, that the amendment (i) will not decrease the balance of the Participant's Deferral Account at the time of the amendment and (ii) will not retroactively decrease the applicable Crediting Rates of the Plan prior to the time of the amendment. EIX may amend the Crediting Rates of the Plan prospectively, in which case the Administrator will notify the Participant of the amendment in writing within 30 days after the amendment.

9.2 Termination of Plan

Subject to the terms of Section 9.3, EIX may at any time terminate the Plan. If EIX terminates the Plan, distributions to the Participants or their Beneficiaries shall be made on the dates on which the Participants or Beneficiaries would receive benefits hereunder without regard to the termination of the Plan except that payments may be made upon termination of the Plan if the requirements for accelerated payment under Treasury Regulation Section 1.409A-3(j)(4)(ix)(C) are satisfied.

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9.3 Amendment or Termination after Change in Control

Notwithstanding the foregoing, EIX will not amend or terminate the Plan without the prior written consent of affected Participants for a period of two calendar years following a Change in Control of EIX (as defined in the EIX 2008 Executive Severance Plan) and will not thereafter amend or terminate the Plan in any manner which affects any Participant (or Beneficiary of a deceased Participant) who commences receiving payment of benefits under the Plan prior to the end of the two-year period following a Change in Control.

9.4 Exercise of Power to Amend or Terminate

EIX's power to amend or terminate the Plan will be exercisable by the Board.

ARTICLE 10

CLAIMS AND REVIEW PROCEDURES

10.1 Claims Procedure

(a)    The Administrator will notify a Participant or his or her Beneficiary (or person submitting a claim on behalf of the Participant or Beneficiary) (a “claimant”) in writing, within 90 days after his or her written application for benefits, of his or her eligibility or noneligibility for benefits under the Plan. If the Administrator determines that a claimant is not eligible for benefits or full benefits, the notice will set forth (1) the specific reasons for the denial, (2) a specific reference to the provisions of the Plan on which the denial is based, (3) a description of any additional information or material necessary for the claimant to perfect his or her claim, and a description of why it is needed, and (4) an explanation of the Plan's claims review procedure and other appropriate information as to the steps to be taken if the claimant wishes to have the claim reviewed. If the Administrator determines that there are special circumstances requiring additional time to make a decision, the Administrator will notify the claimant of the special circumstances and the date by which a decision is expected to be made, and may extend the time for up to an additional 90-day period.

(b)    If a claimant is determined by the Administrator not to be eligible for benefits, or if the claimant believes that he or she is entitled to greater or different benefits, the claimant will have the opportunity to have the claim reviewed by the Administrator by filing a petition for review with the Administrator within 60 days after receipt of the notice issued by the Administrator. Said petition will state the specific reasons which the claimant believes entitle him or her to benefits or to greater or different benefits. Within 60 days after receipt by the Administrator of the petition, the Administrator will afford the claimant (and counsel, if any) an opportunity to present his or her position to the Administrator in writing, and the claimant (or counsel) will have the right to review the pertinent documents. The Administrator will notify the claimant of its decision in writing within the 60-day period, stating specifically the basis of its decision, written in a manner calculated to be understood by the claimant and the specific provisions of the Plan on which the decision is based. If, due to special circumstances (for example, because of the need for a hearing), the 60-day period is not sufficient, the decision may be deferred for up to another 60-day period at the election of the Administrator, but notice of this deferral will be given to the claimant. In the event of the death of the Participant, the same procedures will apply to the Participant's Beneficiaries.

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10.2 Dispute Arbitration

Notwithstanding the foregoing, and because it is agreed that time will be of the essence in determining whether any payments are due to the claimant under the Plan, a claimant may, if he or she desires, submit any claim for payment under the Plan to arbitration. This right to select arbitration will be solely that of the claimant and claimant may decide whether or not to arbitrate in his or her discretion. The "right to select arbitration" is not mandatory on the claimant, and the claimant may choose in lieu thereof to bring an action in an appropriate civil court. Once an arbitration is commenced, however, it may not be discontinued without the mutual consent of both parties to the arbitration. During the lifetime of the Participant only he or she can use the arbitration procedure set forth in this Section.

Any claim for arbitration may be submitted as follows: if a claimant has submitted a request to be paid under the Plan and the claim is finally denied by the Administrator in whole or in part, the claim may be filed in writing with an arbitrator of the claimant's choice who is selected by the method described in the next four sentences. The first step of the selection will consist of the claimant submitting a list of five potential arbitrators to the Administrator. Each of the five arbitrators must be either (1) a member of the National Academy of Arbitrators located in the State of California or (2) a retired California Superior Court or Appellate Court judge. Within one week after receipt of the list, the Administrator will select one of the five arbitrators as the arbitrator for the dispute in question. If the Administrator fails to select an arbitrator within one week after receipt of the list, the claimant will then designate one of the five arbitrators for the dispute in question.

The arbitration hearing will be held within seven days (or as soon thereafter as possible) after the picking of the arbitrator. No continuance of said hearing will be allowed without the mutual consent of the claimant and the Administrator. Absence from or nonparticipation at the hearing by either party will not prevent the issuance of an award. Hearing procedures which will expedite the hearing may be ordered at the arbitrator's discretion, and the arbitrator may close the hearing in his or her sole discretion when he or she decides he or she has heard sufficient evidence to satisfy issuance of an award.

The arbitrator's award will be rendered as expeditiously as possible and in no event later than one week after the close of the hearing.

In the event the arbitrator finds that the Administrator or the Company has breached the terms of the Plan, he or she will order the Company to pay to the claimant within two business days after the decision is rendered the amount then due the claimant, plus, notwithstanding anything to the contrary in the Plan, an additional amount equal to 20% of the amount actually in dispute. The award of the arbitrator will be final and binding upon the Parties.

The award may be enforced in any appropriate court as soon as possible after its rendition. The Administrator will be considered the prevailing party in a dispute if the arbitrator determines (1) that neither the Administrator nor the Company has breached the terms of the Plan and (2) the claim by the claimant was not made in good faith. Otherwise, the claimant will be considered the

12

prevailing party. In the event that the Administrator is the prevailing party, the fee of the arbitrator and all necessary expenses of the hearing (excluding any attorneys' fees incurred by the Administrator) including the fees of a stenographic reporter, if employed, will be paid by the losing party. In the event that the claimant is the prevailing party, the fee of the arbitrator and all necessary expenses of the hearing (including all attorneys' fees incurred by the claimant in pursuing his or her claim and the fees of a stenographic reporter, if employed) will be paid by the Company by March 15 of the year following the year in which the arbitrator determines who is the prevailing party.

ARTICLE 11

MISCELLANEOUS

11.1 Successors

The rights and obligations of EIX and the Companies under the Plan will inure to the benefit of, and will be binding upon, the successors and assigns of EIX and the Companies, respectively.

11.2 Trust

The Companies will be responsible for the payment of all benefits under the Plan. At their discretion, the Companies may establish one or more grantor trusts for the purpose of providing for payment of benefits under the Plan. The trust or trusts may be irrevocable, but a Company's share of the assets thereof will be subject to the claims of the Company's creditors. Benefits paid to the Participant from any such trust will be considered paid by the Company for purposes of meeting the obligations of the Company under the Plan.

11.3 Service Not Guaranteed

Nothing contained in the Plan nor any action taken hereunder will be construed as a contract of service or as giving any Participant any right to continue in service as a director of EIX or any other Affiliate.

11.4 Gender, Singular and Plural

All pronouns and variations thereof will be deemed to refer to the masculine, feminine, or neuter, as the identity of the person or persons may require. As the context may require, the singular may be read as the plural and the plural as the singular.

11.5 Captions

The captions of the articles and sections of the Plan are for convenience only and will not control or affect the meaning or construction of any of its provisions.

11.6 Validity

If any provision of the Plan is held invalid, void or unenforceable, the same will not affect, in any respect whatsoever, the validity of any other provisions of the Plan.

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11.7 Waiver of Breach

The waiver by EIX or the Administrator of any breach of any provision of the Plan by the Participant will not operate or be construed as a waiver of any subsequent breach by the Participant.

11.8 Applicable Law

The Plan will be governed and construed in accordance with the laws of California.

11.9 Notice

Any notice or filing required or permitted to be given to the Administrator under the Plan will be sufficient if in writing and hand-delivered, or sent by first class mail to the principal office of EIX, directed to the attention of the Administrator. The notice will be deemed given as of the date of delivery, or, if delivery is made by mail, as of the date shown on the postmark.

11.10 Statutes and Regulations

Any reference to a statute or regulation herein shall include any successor to such statute or regulation.

IN WITNESS WHEREOF, EIX has adopted this amended and restated Plan effective the 25^th day of October, 2012.

EDISON INTERNATIONAL

/s/ Daryl D. David

__________________________________________

Daryl D. David

Senior Vice President, Human Resources

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EX-10.2

Exhibit 10.2

EDISON INTERNATIONAL

2008 EXECUTIVE DEFERRED COMPENSATION PLAN

Amended and Restated Effective

October 24, 2012

2008 EXECUTIVE DEFERRED COMPENSATION PLAN
TABLE OF CONTENTS
Section	Title	Page
ARTICLE 1 DEFINITIONS		1
ARTICLE 2 DEFERRAL ELECTIONS		4
	2.1 Elections	4
	2.2 Vesting	8
ARTICLE 3 MATCHING CREDITS		8
	3.1 Amount	8
	3.2 Vesting	8
ARTICLE 4 DEFERRAL ACCOUNTS		8
	4.1 Deferral Accounts	8
	4.2 Timing of Credits	8
	4.3 Statement of Accounts	9
ARTICLE 5 PAYMENT ELECTIONS		9
	5.1 Primary Payment Election	9
	5.2 Contingent Payment Election	10
	5.3 Changes to Payment Elections	11
	5.4 Small Benefit Exception	11
	5.5 Six-Month Delay in Payment for Specified Employees	11
	5.6 Conflict of Interest Exception, Etc	11
ARTICLE 6 SURVIVOR BENEFITS		12
	6.1 Payment	12
	6.2 Special Increase	12
ARTICLE 7 BENEFICIARY DESIGNATION		12
ARTICLE 8 CONDITIONS RELATED TO BENEFITS		13
	8.1 Nonassignability	13
	8.2 Unforeseeable Emergency Distribution	13
	8.3 No Right to Assets	13
	8.4 Protective Provisions	14
	8.5 Constructive Receipt	14
	8.6 Withholding	14
	8.7 Incapacity	15

i

2008 EXECUTIVE DEFERRED COMPENSATION PLAN
TABLE OF CONTENTS
Section	Title	Page
ARTICLE 9 PLAN ADMINISTRATION		15
	9.1 Plan Interpretation	15
	9.2 Limited Liability	15
ARTICLE 10 AMENDMENT OR TERMINATION OF PLAN		15
	10.1 Amendment of Plan	15
	10.2 Termination of Plan	15
	10.3 Amendment or Termination after Change in Control	16
	10.4 Exercise of Power to Amend or Terminate	16
ARTICLE 11 CLAIMS AND REVIEW PROCEDURES		16
	11.1 Claims Procedure for Claims Other Than for Vesting due to Disability	16
	11.2 Claims Procedure for Claims due to Disability	17
	11.3 Dispute Arbitration	18
ARTICLE 12 MISCELLANEOUS		19
	12.1 Successors	19
	12.2 Trust	19
	12.3 Employment Not Guaranteed	19
	12.4 Gender, Singular and Plural	19
	12.5 Captions	20
	12.6 Validity	20
	12.7 Waiver of Breach	20
	12.8 Applicable Law	20
	12.9 Notice	20
	12.10 ERISA Plan	20
	12.11 Statutes and Regulations	20

ii

EDISON INTERNATIONAL

2008 EXECUTIVE DEFERRED COMPENSATION PLAN

Amended and Restated Effective October 24, 2012

PREAMBLE

The purpose of this Plan is to provide Eligible Employees of participating Affiliates with the opportunity to defer payment and taxation of some elements of their compensation.

This Plan applies to amounts arising from deferrals of compensation earned or determined after December 31, 2004 and to amounts that vested after December 31, 2004, and is intended to comply with Section 409A of the Internal Revenue Code and the regulations issued thereunder. This version of the Plan applies to amounts arising from deferrals of compensation pursuant to deferral elections made on or after December 1, 2012; however any deferral elections made after this date with respect to Salary or Bonus amounts earned for services performed during the 2012 Plan Year by an employee who first becomes an Eligible Employee during 2012 shall be subject to the terms and conditions of this Plan as in effect at the beginning of the 2012 calendar year. For the terms and conditions applicable to amounts deferred under this Plan pursuant to deferral elections made prior to that date, refer to the version of this Plan as in effect at the time of the applicable deferral election.

ARTICLE 1

DEFINITIONS

Capitalized terms in the text of the Plan are defined as follows:

Administrator means the Compensation and Executive Personnel Committee of the Board of Directors of EIX.

Affiliate means EIX or any corporation or entity which (i) along with EIX, is a component member of a "controlled group of corporations" within the meaning of Section 414(b) of the Code, and (ii) has approved the participation of its Executives in the Plan.

Beneficiary means the person or persons or entity designated as such in accordance with Article 7 of the Plan.

Board means the Board of Directors of EIX.

Bonus means the dollar amount of bonus awarded by the Employer to the Participant pursuant to the terms of the Executive Incentive Compensation Plan, the 2007 Performance Incentive Plan, or a successor plan governing annual executive bonuses, before reductions for deferrals under the Plan, provided such award constitutes “performance-based compensation” within the meaning of Treasury Regulation Section 1.409A-1(e).

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Change in Control means a Change in Control of EIX as defined in the Severance Plan.

Code means the Internal Revenue Code of 1986, as amended.

Contingent Event means the Participant's Disability or death while employed by an Affiliate or Separation from Service for other reasons if such event occurs prior to the Participant's Retirement.

Contingent Payment Election means an election regarding the time and form of payment made or deemed made in accordance with Section 5.2.

Crediting Rate means the rate at which interest will be credited to Deferral Accounts. The rate will be determined annually in advance of the calendar year and will be equal to the average monthly Moody's Corporate Bond Yield for Baa Public Utility Bonds for the 60 months preceding November 1st of the prior year. EIX reserves the right to prospectively change the definition of Crediting Rate.

Deferral Account means the notional account established for record keeping purposes for a Participant pursuant to Article 4 of the Plan.

Deferral Election means the Participant's written election to defer amounts under the Plan, submitted to the Administrator in the manner prescribed by the Administrator.

Deferral Period means the Plan Year covered by a valid Deferral Election previously submitted by a Participant, or in the case of a newly eligible Participant, the balance of the Plan Year following the date of the Deferral Election.

Disability means the Participant (i) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve months or (ii) is, by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than twelve months, receiving income replacement benefits for a period of not less than three months under a plan covering employees of the Employer.

Dividend Equivalent means an amount equal to the dividend declared by the Board on one share of EIX common stock for any calendar quarter.

EIX means Edison International.

Eligible Employee means an Executive of an Affiliate, who (i) is a U.S. employee or an expatriate who is based and paid in the U.S., (ii) is designated by the Administrator as eligible to participate in the Plan (subject to the restriction in Section 8.2 of the Plan), and (iii) qualifies as a member of a "select group of management or highly compensated employees" under ERISA.

Employer means the Affiliate employing the Participant. Notwithstanding the foregoing, with respect to a particular Participant's benefits under the Plan, for purposes of determining which Affiliate is obligated to pay such benefits, Employer as to such Participant and benefits means the Affiliate employing the Participant upon the Participant's Separation from Service (or, as to any distribution of any benefit under the Plan prior to the Participant's Separation from Service, the Affiliate employing the Participant at the time of such distribution).

ERISA means the Employee Retirement Income Security Act of 1974, as amended.

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Executive means an employee of an Affiliate who is designated an Executive by the CEO of that Affiliate or who is elected as a Vice President or officer of higher rank by the board of that Affiliate or by the Board.

Executive Salary Deferral means the percentage deferred from Salary under this Plan. The Executive Salary Deferral is subtracted from Salary before Savings Plan contributions are calculated.

Matching Credits means the credits added to the Participant's Deferral Account under Article 3.

Matching Base means the amount of the Executive Salary Deferral plus the amount, if any, by which the Participant's Salary in a calendar year minus the Executive Salary Deferral for that calendar year exceeds the Code Section 401(a)(17) compensation limit.

Participant means an Eligible Employee who has completed a Deferral Election with respect to future payments pursuant to Article 2 of the Plan, or an employee or former employee who has a Deferral Account balance.

Payment Election means a Primary Payment Election or a Contingent Payment Election.

Plan means the EIX 2008 Executive Deferred Compensation Plan.

Plan Year means the calendar year.

Primary Payment Election means an election regarding the time and form of payments made or deemed made in accordance with Section 5.1.

Qualifying Award means an award granted to an Eligible Employee under the EIX Management Long-Term Incentive Compensation Plan, the EIX Officer Long-Term Incentive Compensation Plan, the EIX Equity Compensation Plan, or the EIX 2007 Performance Incentive Plan, other than an EIX nonqualified stock option, and evidenced in writing that provides (or is amended to provide) that the award may be deferred under this Plan.

Retirement means a Separation from Service under terms constituting a retirement for purposes of the EIX 2008 Executive Retirement Plan.

Salary means the Participant's basic pay from the Employer (excluding Bonuses, Special Awards, commissions, severance pay, and other non-regular forms of compensation) before reductions for deferrals under the Plan or the Savings Plan.

Savings Plan means the Edison 401(k) Savings Plan.

Separation from Service occurs when a Participant dies, retires, or otherwise has a termination of employment from the Employer that constitutes a “separation from service” within the meaning of Treasury Regulation Section 1.409A-1(h)(1), without regard to the optional alternative definitions available thereunder.

Severance Plan means the EIX 2008 Executive Severance Plan (or any similar successor plan).

Similar Plan means a plan required to be aggregated with this Plan under Treasury Regulation Section 1.409A-1(c)(2)(i).

Special Award means an award other than Salary, Bonus or a Qualifying Award that is payable in cash at a future date.

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Specified Employee means a Participant who is designated as an elected Vice President or above by the Administrator, using the identification date and methods determined by the Administrator.

Termination of Employment means the voluntary or involuntary Separation from Service for any reason other than Retirement or death.

Unforeseeable Emergency means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant's Beneficiary, or the Participant's spouse or dependent (as defined in Code Section 152, without regard to Sections 152(b)(1), (b)(2) and (d)(1)(B)); loss of the Participant's property due to casualty (including the need to rebuild a home following damage to a home not otherwise covered by insurance, for example, not as a result of a natural disaster); or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the Participant's control.

Valuation Date means the last day of the month in which the final day of employment falls prior to Separation from Service, unless distribution is scheduled or required to commence on a date other than the first day of the month following Separation from Service, in which latter case Valuation Date means the day before distribution is scheduled or required to commence.

Years of Service. Years of vesting service credited under the terms of the EIX 2008 Executive Retirement Plan.

ARTICLE 2

DEFERRAL ELECTIONS

2.1 Elections

(a)Salary. An Eligible Employee may elect to defer Salary under the Plan by submitting a Salary Deferral Election to the Administrator specifying the whole percentage of Salary to be deferred prior to the beginning of the Plan Year during which the Eligible Employee performs the services for which such Salary is to be earned. The maximum Salary Deferral is 75% of Salary. Once made, a Salary Deferral Election (including any election regarding time and form of payment) will continue to apply for subsequent Deferral Periods unless (i) the Eligible Employee submits a new Salary Deferral Election during a subsequent enrollment period changing the deferral amount or revoking the existing election, or (ii) the Participant is not an Eligible Employee on the last day of a subsequent enrollment period.

(b)Bonus. An Eligible Employee may elect to defer some or all of his or her Bonus by submitting a Bonus Deferral Election to the Administrator prior to the date that is six months before the end of the performance period and in no event later than the date the Bonus has become readily ascertainable. Notwithstanding the foregoing, either generally or as to a particular Bonus, the Administrator may, but need not, require that Bonus Deferral Elections be submitted to the Administrator prior to the beginning of the Plan Year during which the Eligible Employee performs the services for which such Bonus is to be earned. The maximum Bonus Deferral is 100% of Bonus.

Once made, a Bonus Deferral Election (including any election regarding time and form of payment) will continue to apply for subsequent Deferral Periods unless (i) the Eligible Employee submits a new Bonus Deferral Election during a subsequent enrollment period changing the

4

deferral amount or revoking the existing election, or (ii) the Participant is not an Eligible Employee on the last day of a subsequent enrollment period.

(c)Initial Eligibility. Notwithstanding the foregoing, an employee who first becomes an Eligible Employee during a Plan Year may make an initial Deferral Election for the deferral of Salary or Bonus, provided that such Eligible Employee has not previously become eligible to participate in this or any Similar Plan. Any Salary Deferral Election must be made within thirty days after the date the employee becomes an Eligible Employee and shall apply to Salary earned for services performed after the election is submitted to the Administrator. If the employee first becomes an Eligible Employee prior to establishment of the performance criteria for a Bonus, the Eligible Employee may make the Bonus Deferral Election prior to the date that is six months before the end of the performance period but not later than the date the Bonus has become readily ascertainable. If the employee first becomes an Eligible Employee after establishment of the performance criteria or less than six months before the end of the Deferral Period, such Bonus Deferral Election must be made within thirty days after the date the employee becomes an Eligible Employee and shall apply to that portion of the Bonus earned during the Plan Year multiplied by the ratio of the number of days remaining in the calendar year after the election is submitted to the Administrator to the total number of days during the Plan Year that such Employee is employed by an Affiliate.

(d)Qualifying Awards. An Eligible Employee may elect to defer payment of some or all of his or her Qualifying Awards by submitting a Qualifying Award Deferral Election to the Administrator specifying the whole percentage of his or her Qualifying Awards to be deferred. With respect to a Qualifying Award that was granted on or before December 31, 2012 with respect to a performance period scheduled to end on or after December 31, 2013, and that is “performance-based compensation” within the meaning of Treasury Regulation Section 1.409A-1(e), the Eligible Employee must submit his or her Qualifying Award Deferral Election to the Administrator not later than December 31, 2012. Otherwise, the Participant must submit his or her Qualifying Award Deferral Election to the Administrator prior to the beginning of the Plan Year in which such Qualifying Award is granted.

In the circumstances provided in the next two sentences, the Administrator may, but need not, extend the applicable Qualifying Award Deferral Election deadlines either generally or as to a particular Qualifying Award.  With respect to any Qualifying Award that qualifies as “performance-based compensation,” within the meaning of Treasury Regulation Section 1.409A‑1(e), the Administrator may permit the Qualifying Award Deferral Election to be made prior to the date that is six months before the end of the performance period and in no event later than the date the Qualifying Award has become readily ascertainable. With respect to any Qualifying Award that is subject to a substantial risk of forfeiture at grant, the Administrator may permit the Qualifying Award Deferral Election to be made not more than thirty days following the date the Qualifying Award is granted, provided that the Deferral Election is not made later than the date that is twelve months before the Qualifying Award could cease to be subject to a substantial risk of forfeiture other than due to death, Disability or a change in the ownership or effective control or a change in the ownership of a substantial portion of the assets of EIX within the meaning of Treasury Regulation Section 1.409A-3(i)(5).

Notwithstanding the foregoing, an employee who first becomes an Eligible Employee during a Plan Year may make an initial Deferral Election for the deferral of some or all of his or her

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Qualifying Awards, provided that such Eligible Employee has not previously become eligible to participate in this or any Similar Plan. Such Qualifying Award Deferral Election must be made within thirty days after the date the employee becomes an Eligible Employee. The Deferral Election shall apply to the entire specified portion of the Qualifying Award to which it relates if either (i) the Qualifying Award qualifies as “performance-based compensation,” within the meaning of Treasury Regulation Section 1.409A-1(e), and the Qualifying Award Deferral Election is made prior to the establishment of performance criteria for the Qualifying Award and the date that is six months before the end of the performance period and in no event later than the date the Qualifying Award has become readily ascertainable, or (ii) the Qualifying Award is subject to a substantial risk of forfeiture at grant and the Qualifying Award Deferral Election is made not more than thirty days following the date the Qualifying Award is granted, provided that the Deferral Election is not made later than the date that is twelve months before the Qualifying Award could cease to be subject to a substantial risk of forfeiture other than due to death, Disability or a change in the ownership or effective control or a change in the ownership of a substantial portion of the assets of EIX within the meaning of Treasury Regulation Section 1.409A-3(i)(5). If the preceding sentence does not apply, the Qualifying Award Deferral Election shall apply to that portion of the related Qualifying Award multiplied by the ratio of the number of days remaining in the applicable performance period (or the number of days remaining in the applicable service period if the Qualifying Award is not a performance-based vesting award) after the election is submitted to the Administrator to the total number of days during that performance period (or that service period, as the case may be) that such Employee is employed by an Affiliate.

The Qualifying Award remains subject to all applicable limitations as to the time or times during which it may become payable or the conditions for payment as provided in the terms and conditions of the Qualifying Award. Once made, a Qualifying Award Deferral Election (including any election regarding time and form of payment) will continue to apply for subsequent Deferral Periods unless (i) the Eligible Employee submits a new Qualifying Award Deferral Election during a subsequent enrollment period changing the deferral amount or revoking the existing election, or (ii) the Participant is not an Eligible Employee on the last day of a subsequent enrollment period; provided that a Deferral Election made prior to December 1, 2012 shall not be given effect as to any Qualifying Award to the extent that the Participant had the ability on or after December 1, 2012 to make a new Deferral Election as to that Qualifying Award.

(e)Special Awards. An Eligible Employee may elect to defer payment of some or all of his or her Special Awards by submitting a Special Award Deferral Election to the Administrator specifying the whole percentage of his or her Special Awards to be deferred. With respect to any Special Awards that are “performance-based compensation,” within the meaning of Treasury Regulation Section 1.409A-1(e), the Eligible Employee must submit his or her Special Award Deferral Election to the Administrator prior to the date that is six months before the end of the performance period and in no event later than the date the Special Award has become readily ascertainable. With respect to any Special Awards that are not “performance-based compensation,” within the meaning of Treasury Regulation Section 1.409A-1(e), the Eligible Employee must submit his or her Special Award Deferral Election to the Administrator either (i) in the case of a Special Award that is subject to a substantial risk of forfeiture at grant, within thirty days following the date the Special Award is granted, but in no event later than the date

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that is twelve months before the Special Award could cease to be subject to a substantial risk of forfeiture other than due to death, Disability or a change in the ownership or effective control or a change in the ownership of a substantial portion of the assets of EIX within the meaning of Treasury Regulation Section 1.409A-3(i)(5), or (ii) otherwise, prior to the beginning of the Plan Year in which such Special Award is given.

An employee who first becomes an Eligible Employee during a Plan Year may make an initial Deferral Election for the deferral of some or all of his or her Special Awards, provided that such Eligible Employee has not previously become eligible to participate in this or any Similar Plan. Such Special Award Deferral Election must be made within thirty days after the date the employee becomes an Eligible Employee. The Deferral Election shall apply to the entire specified portion of the Special Award to which it relates if either (i) the Special Award qualifies as “performance-based compensation,” within the meaning of Treasury Regulation Section 1.409A-1(e), and the Special Award Deferral Election is made prior to the establishment of performance criteria for the Special Award and the date that is six months before the end of the performance period and in no event later than the date the Special Award has become readily ascertainable, or (ii) the Special Award is subject to a substantial risk of forfeiture at grant and the Special Award Deferral Election is made not more than thirty days following the date the Special Award is granted, provided that the Deferral Election is not made later than the date that is twelve months before the Special Award could cease to be subject to a substantial risk of forfeiture other than due to death, Disability or a change in the ownership or effective control or a change in the ownership of a substantial portion of the assets of EIX within the meaning of Treasury Regulation Section 1.409A-3(i)(5). If the preceding sentence does not apply, the Special Award Deferral Election shall apply to that portion of the related Special Award multiplied by the ratio of the number of days remaining in the applicable performance period (or the number of days remaining in the applicable service period if the Special Award is not a performance-based vesting award) after the election is submitted to the Administrator to the total number of days during that performance period (or that service period, as the case may be) that such Employee is employed by an Affiliate.

Notwithstanding the foregoing, either generally or as to a particular Special Award, the Administrator may, but need not, require that Special Award Deferral Elections be submitted to the Administrator prior to the beginning of the Plan Year in which such Special Award is given.

The Special Award remains subject to all applicable limitations as to the time or times during which it may become payable or the conditions for payment as provided in the terms and conditions of the Special Award. Once made, a Special Award Deferral Election (including any election regarding time and form of payment) will continue to apply for subsequent Deferral Periods unless (i) the Eligible Employee submits a new Special Award Deferral Election during a subsequent enrollment period changing the deferral amount or revoking the existing election, or (ii) the Participant is not an Eligible Employee on the last day of a subsequent enrollment period; provided that a Deferral Election made prior to December 1, 2012 shall not be given effect as to any Special Award to the extent that the Participant had the ability on or after December 1, 2012 to make a new Deferral Election as to that Special Award.

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2.2 Vesting

Amounts deferred under this Article 2 and any earnings thereon will be 100% vested at all times. Notwithstanding the foregoing, any Special Award deferred under Section 2.1(e) and any earnings thereon may be subject to vesting terms. Any such deferred Special Award shall fully vest upon the Participant's Separation from Service if the Participant is entitled to receive benefits under the Severance Plan and has satisfied all conditions for such benefits.

ARTICLE 3

MATCHING CREDITS

3.1 Amount

Matching Credits in each calendar year will be added by the Employer to the Participant's Deferral Account under this Plan equal to (i) the lesser of the amount of Salary earned in the calendar year and deferred under the Plan or 6% of the Participant's Matching Base for the calendar year, plus (ii) the lesser of one-half of the amount of Bonus deferred under the Plan or 3% of the Bonus. Matching Credits added to the Participant's Deferral Account shall be subject to the payment election provisions of Article 5 (and, for the avoidance of doubt, will become payable pursuant to the Deferral Election made or deemed made in the year prior to the calendar year the Matching Credits are added to the Participant's Deferral Account).

3.2 Vesting

The Participant's Matching Credits and earnings thereon will vest (i) when the Participant has completed five Years of Service with an Affiliate, (ii) upon the Participant's Disability while employed with an Affiliate, (iii) upon the Participant's death while employed with an Affiliate, or (iv) upon the Participant's Separation from Service if the Participant is entitled to benefits under the Severance Plan and has satisfied all conditions for such benefits.

ARTICLE 4

DEFERRAL ACCOUNTS

4.1 Deferral Accounts

Solely for record keeping purposes, the Administrator will maintain a Deferral Account for each Participant with such subaccounts as the Administrator or its record keeper finds necessary or convenient in the administration of the Plan.

4.2 Timing of Credits

(a)Salary, Bonus and Special Award Deferrals. The Administrator will credit to the Participant's Deferral Account the Salary, Bonus and Special Award deferrals under Article 2 at the time such amounts would otherwise have been paid to the Participant but for the Deferral Election.

(b)Matching Credits. Matching Credits under Article 3 will be credited (conditionally until vested) to the Deferral Account at the same time the related deferrals are credited to the Deferral Account.

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(c)Qualifying Awards. As of the date immediately following the vesting or performance period of a Qualifying Award, or as of the ex-dividend date in the case of Dividend Equivalents, a Participant's Deferral Account will be credited with the deferred amount.

(d)Interest Crediting Dates. The Administrator will credit interest at the Crediting Rate to the Participant's Deferral Account on a daily basis, compounded annually.

4.3 Statement of Accounts

The Administrator will periodically either provide or make available to each Participant a statement setting forth the balance of the Deferral Account maintained for the Participant.

ARTICLE 5

PAYMENT ELECTIONS

5.1 Primary Payment Election

As part of a Deferral Election, a Participant may make a Primary Payment Election specifying the payment schedule for each subaccount that will be created as a result of the Deferral Election. The choices available for a Primary Payment Election are as follows:

(a)Monthly installments for 60 to 180 months; or

(b)A single lump sum; or

(c)Two to fifteen installments paid annually; or

(d)Any combination of the preceding three choices.

Payments under this Primary Payment Election may commence upon (i) the first day of a specified month and year that may be no later than the month and year in which the Participant attains age 75; (ii) the Participant's Retirement; or (iii) the first day of the month that is a specified number of months following the Participant's Retirement or the first day of a specified month a specified number of years following the calendar year in which Retirement occurs (provided that if the date otherwise determined pursuant to this clause (iii) is later than the month and year in which the Participant attains age 75, the date pursuant to this clause (iii) shall be the later of the Participant's Retirement or the month and year in which the Participant attains age 75).

Subject to Section 5.5, lump sum payments or initial installment payments will be made within 60 days of the scheduled dates. Interest will be added to the payment amount for the days elapsed between the scheduled payment date and the actual date of payment. Notwithstanding anything to the contrary in a Participant Deferral Election, payments from a Participant's Deferral Account will be subject to the following earliest payment date rules: (i) no subaccount relating to a Bonus Deferral Election may be scheduled to commence payment or be paid until the first day of the fourth month in the Plan Year immediately following the Plan Year for which the Bonus was awarded (for example, April 1, 2014 as to a Bonus awarded for 2013); and (ii) no subaccount relating to a Qualifying Award Deferral Election or Special Award Deferral Election with respect to “performance-based compensation” within the meaning of Treasury Regulation Section 1.409A-1(e) may be scheduled to commence payment or be paid until the first day of the fourth month in the Plan Year immediately following the Plan Year in which the corresponding

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performance period is scheduled to end. If the foregoing earliest payment date rules apply to any payment to be paid in installments, the first installment shall be paid on the applicable earliest payment date and subsequent installments shall be paid over the applicable installment period. The foregoing earliest payment date rules shall apply to payments under both Primary Payment Elections and Contingent Payment Elections.

If paid in installments, the installments will be paid in amounts that will amortize the Deferral Account or subaccount balance with interest credited at the Crediting Rate over the period of time benefits are to be paid. For purposes of calculating installments, the Deferral Account or subaccount will be valued as of the Valuation Date and subsequently as of December 31 each year with subsequent installments adjusted for the next calendar year according to procedures established by the Administrator. Notwithstanding anything herein to the contrary, distribution in installments shall be treated as a single payment as of the date of the initial installment for purposes of Section 409A of the Code. If paid in monthly installments, the installments may be paid in a single check each month or in more than one check for any given month, provided that in either such case the total amount of the monthly payment shall not change.

If no Primary Payment Election has been made, the Primary Payment Election shall be deemed to be a single lump sum upon the Participant's Retirement (or, if earlier, the Participant's death or Disability).

5.2 Contingent Payment Election

As part of a Deferral Election, a Participant may make a Contingent Payment Election for each of the Contingent Events of (1) the Participant's death while employed by an Affiliate, (2) the Participant's Disability while employed by an Affiliate and (3) Termination of Employment, for each subaccount that will be created as a result of the Deferral Election, which Contingent Payment Election will take effect upon the first Contingent Event, if any, that occurs before the Participant's Retirement (if the Participant specified a payment schedule determined by reference to Retirement in Section 5.1) or the first day of a specified month and year elected by the Participant pursuant to Section 5.1. The choices available for the Contingent Payment Election are those specified in Section 5.1 except that the references to Retirement shall instead refer to the applicable Contingent Event.

If the Participant has made no Contingent Payment Election and a Contingent Event occurs prior to Retirement (if the Participant specified a payment schedule determined by reference to Retirement in Section 5.1) or the first day of a specified month and year elected by the Participant pursuant to Section 5.1, the Administrator will pay the benefit as specified in the Participant's Primary Payment Election, except that payments scheduled for payment or commencement of payment “upon Retirement,” or with a payment date determined by reference to “Retirement,” will be paid, commence, or have payment determined by a reference to, the first day of the month following the month in which the Contingent Event occurs. If the Participant has made neither a Contingent Payment Election nor a Primary Payment Election and a Contingent Event occurs prior to Retirement, the Payment Election shall be deemed to be a single lump sum upon the Participant's Contingent Event, subject to the earliest payment date rules in Section 5.1.

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5.3 Changes to Payment Elections

Participants may change a Primary Payment Election or Contingent Payment Election, including a deemed Payment Election, after the period allowed for the initial Deferral Election by submitting a new written Payment Election to the Administrator in the manner prescribed by the Administrator, subject to the following conditions: (1) the new Payment Election shall not be effective unless made at least twelve months before the payment or commencement date scheduled under the prior Payment Election; (2) the new Payment Election must defer a lump sum payment or commencement of installment payments for a period of at least five years from the date that the lump sum would have been paid or installment payments would have commenced under the prior Payment Election and (3) the election shall not be effective until twelve months after it is submitted to the Administrator. If at the time a new Payment Election is submitted, the Administrator determines that imposition of the five-year delay would require that a Participant's payments begin after he or she has attained age 75, then the Participant will not be permitted to make a new Payment Election. The payment schedules available under a new Payment Election are those specified in Section 5.1 and 5.2 (as applicable), subject to the conditions specified in this paragraph.

5.4 Small Benefit Exception

Notwithstanding the foregoing, the Administrator may, in its sole discretion and as determined by it in writing, pay the benefits in a single lump sum if the sum of all benefits payable to the Participant under this Plan and all Similar Plans is less than or equal to the applicable dollar amount under Section 402(g)(1)(B) of the Code.

5.5 Six-Month Delay in Payment for Specified Employees

Notwithstanding anything herein to the contrary, in the event that a Participant who is a Specified Employee is entitled to a distribution from the Plan due to the Participant's Separation from Service, the lump sum payment or the commencement of installment payments, as the case may be, may not be scheduled to occur or occur before the date that is the earlier of (1) six months following the Participant's Separation from Service for reasons other than death or (2) the Participant's death.

5.6 Conflict of Interest Exception, Etc.

Notwithstanding the foregoing, the Administrator may, in its sole discretion, pay benefits in a single lump sum if permitted under Treasury Regulation Section 1.409A-3(j)(4)(iii). In addition, the Administrator may, in its sole discretion, accelerate the payment of benefits if and to the extent permitted under any of the other exceptions specified in Treasury Regulation Section 1.409A-3(j)(4) to the general rule in Section 409A of the Code prohibiting accelerated payments, provided that the terms of Section 5.4 of the Plan shall govern whether benefits will be paid in a single lump sum pursuant to the small benefit exception contained in Treasury Regulation Section 1.409A-3(j)(4)(v).

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ARTICLE 6

SURVIVOR BENEFITS

6.1 Payment

Following the Participant's death, payment of the Participant's Deferral Account will be made to the Participant's Beneficiary or Beneficiaries according to the payment schedule elected or deemed elected according to Article 5.

6.2 Special Increase

This Section 6.2 applies as to any Participant who was first an Eligible Employee under this Plan on or before December 31, 2008. If any such Participant's death occurs within the first 10 years following the date on which he or she first became an Eligible Employee, the balance existing on the date of the Participant's death shall be doubled, excluding the portion of the balance derived from deferrals and earnings thereon of Qualifying Awards and of Special Awards unless the Special Award specifies such doubling. The doubled balance will be paid out according to the payment schedule elected or deemed elected according to Article 5. For the avoidance of doubt, the death benefit provided in this Section 6.2 is intended as a separate plan within the meaning of Section 409A of the Code and Treasury Regulation Section 1.409A-1(c).

ARTICLE 7

BENEFICIARY DESIGNATION

The Participant will have the right, at any time, to designate any person or persons as Beneficiary (both primary and contingent) to whom payment under the Plan will be made in the event of the Participant's death. The Beneficiary designation will be effective when it is submitted to the Administrator during the Participant's lifetime in accordance with procedures established by the Administrator.

The submission of a new Beneficiary designation will cancel all prior Beneficiary designations. Any finalized divorce or marriage of a Participant subsequent to the date of a Beneficiary designation will revoke such designation, unless in the case of divorce the previous spouse was not designated as a Beneficiary, and unless in the case of marriage the Participant's new spouse has previously been designated as Beneficiary. The spouse of a married Participant must consent in writing to any designation of a Beneficiary other than the spouse.

If a Participant fails to designate a Beneficiary as provided above, or if the Beneficiary designation is revoked by marriage, divorce, or otherwise without execution of a new designation, or if every person designated as Beneficiary predeceases the Participant, then the Administrator will direct the distribution of the benefits to the Participant's estate. If a primary Beneficiary dies after the Participant's death but prior to completion of benefits under this Plan, and no contingent Beneficiary has been designated by the Participant, any remaining payments will be paid to the primary Beneficiary's Beneficiary, if one has been designated, or to the Beneficiary's estate.

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ARTICLE 8

CONDITIONS RELATED TO BENEFITS

8.1 Nonassignability

The benefits provided under the Plan may not be alienated, assigned, transferred, pledged or hypothecated by or to any person or entity, at any time or any manner whatsoever. These benefits will be exempt from the claims of creditors of any Participant or other claimants and from all orders, decrees, levies, garnishment or executions against any Participant to the fullest extent allowed by law. Notwithstanding the foregoing, the benefit payable to a Participant may be assigned in full or in part, pursuant to a domestic relations order of a court of competent jurisdiction.

8.2 Unforeseeable Emergency Distribution

A Participant may submit a hardship distribution request to the Administrator in writing setting forth the reasons for the request. The Administrator (or its delegate) will have the sole authority to approve or deny such requests. Upon a finding that the Participant has suffered an Unforeseeable Emergency, the Administrator (or its delegate) may in its discretion, permit the Participant to cease any on-going deferrals and accelerate distributions of benefits under the Plan in the amount reasonably necessary to alleviate the Unforeseeable Emergency. If a distribution is to be made to a Participant on account of an Unforeseeable Emergency, the Participant may not make deferrals under the Plan until one entire Plan Year following the Plan Year in which a distribution based on an Unforeseeable Emergency was made has elapsed.

8.3 No Right to Assets

A Participant's benefits paid under the Plan will be paid from the general funds of the Participant's Employer, and the Participant and any Beneficiary will be no more than unsecured general creditors of that Employer with no special or prior right to any assets of the Employer for payment of any obligations hereunder. Neither the Participant nor the Beneficiary will have a claim to benefits from any other Affiliate. Plan benefits are available to Eligible Employees of EIX and its participating Affiliates. Amounts of compensation deferred by Participants pursuant to this Plan accrue as liabilities of the Employer under the terms and conditions set forth herein. By electing to defer compensation under the Plan, Participants consent to EIX sponsorship of the Plan, but acknowledge that EIX is not a guarantor of the benefit obligations of other participating Affiliates. Each Affiliate is responsible for payment of the accrued benefits under the Plan with respect to its own Eligible Employees subject to the terms and conditions set forth herein. Notwithstanding the foregoing or anything in the definition of “Employer” to the contrary, and at the sole discretion of EIX, EIX may determine that for purposes of benefits payable under the Plan, EIX shall be deemed to be the Employer obligated to pay such benefits. Such an election by EIX may be made, in EIX's sole discretion, as to all Plan benefits, as to only certain benefits, and/or as to only certain Affiliates or Participants, and will be deemed an assumption of the specified benefit obligations of the applicable Affiliates. Subject to the further provisions hereof, EIX will be solely obligated to pay any such benefits and no Participant (or Beneficiary) will have a claim as to any other Affiliate with respect to such benefits. Upon an election by EIX under this Section 8.3, benefits covered by the election will be paid from the general funds of EIX (and not the Affiliate that would otherwise pay the benefits), provided that EIX may require

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that as between EIX and the Affiliate that would otherwise pay such benefits, the Affiliate will be responsible to pay EIX for the assumption of such obligations in accordance with funding arrangements determined by EIX at the time of election or any time thereafter. To the extent such Affiliate fails to comply with such funding arrangements or obtains any refund or offset of payments made from the Affiliate to EIX without the consent of EIX, the Affiliate that would otherwise be responsible for payment of benefits to the applicable Participant will remain responsible for such benefits. EIX will effectuate any such election pursuant to this Section 8.3 by providing written notice to the Administrator and the applicable Affiliates regarding the effective date of such election, and the benefits, Affiliates and Participants for which the election is applicable. The funding arrangements established by EIX at the time of its election, or from time to time thereafter, will set forth the method by which the Affiliates will remit funds to EIX in consideration of compensation that would otherwise be paid by the Affiliate but which has been deferred and is or becomes a Plan benefit obligation of EIX or other Plan benefit obligations that are assumed by EIX. Such a method may include, but is not limited to, lump sum payment by an Affiliate to EIX of relevant benefits accrued through the date of EIX's election with regular periodic payments to EIX of continuing accruals; regular periodic payments by an Affiliate to EIX beginning with the date of EIX's election through the date such benefits become due under the Plan; lump sum payment by an Affiliate to EIX at the time benefits become due under the Plan; or intercompany payables and receivables used with funding on a “pay-as-you-go” basis.

8.4 Protective Provisions

The Participant will cooperate with the Administrator by furnishing any and all information requested by the Administrator, in order to facilitate the payment of benefits hereunder, taking such physical examinations as the Administrator may deem necessary and signing such consents to insure or taking such other actions as may be requested by the Administrator. If the Participant refuses to cooperate, the Administrator and the Employer will have no further obligation to the Participant under the Plan.

8.5 Constructive Receipt

Notwithstanding anything to the contrary in this Plan, in the event the Administrator determines that amounts deferred under the Plan have failed to comply with Section 409A and must be recognized as income for federal income tax purposes, distribution of the amounts included in a Participant's income will be made to such Participant. The determination of the Administrator under this Section 8.5 will be binding and conclusive.

8.6 Withholding

The Participant or the Beneficiary will make appropriate arrangements with the Administrator for satisfaction of any federal, state or local income tax withholding requirements and Social Security or other employee tax requirements applicable to the accrual or payment of benefits under the Plan. If no other arrangements are made, the Administrator may provide, at its discretion, for such withholding and tax payments as may be required.

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8.7 Incapacity

If any person entitled to payments under this Plan is incapacitated and unable to use such payments in his or her own best interest, EIX may direct that payments (or any portion) be made to that person's legal guardian or conservator, or that person's spouse, as an alternative to payment to the person unable to use the payments. EIX will have no obligation to supervise the use of such payments, and court-appointed guardianship or conservatorship may be required.

ARTICLE 9

PLAN ADMINISTRATION

9.1 Plan Interpretation

The Administrator will administer the Plan and interpret, construe and apply its provisions in accordance with its terms and will provide direction and oversight as necessary to management, staff, or contractors to whom day-to-day Plan operations may be delegated. The Administrator will establish, adopt or revise such rules and regulations as it may deem necessary or advisable for the administration of the Plan. The Administrator will interpret and construe the Plan and the prior version of the Plan to comply with Section 409A of the Code. All decisions of the Administrator will be final and binding.

9.2 Limited Liability

Neither the Administrator, nor any of its members or designees, will be liable to any person for any action taken or omitted in connection with the interpretation and administration of this Plan.

ARTICLE 10

AMENDMENT OR TERMINATION OF PLAN

10.1 Amendment of Plan

Subject to the terms of Section 10.3, EIX may at any time amend the Plan in whole or in part, provided, however, that the amendment (i) will not decrease the balance of the Participant's Deferral Account at the time of the amendment and (ii) will not retroactively decrease the applicable Crediting Rates of the Plan prior to the time of the amendment. EIX may amend the Crediting Rates of the Plan prospectively, in which case the Administrator will notify the Participant of the amendment in writing within 30 days after the amendment.

10.2 Termination of Plan

Subject to the terms of Section 10.3, EIX may at any time terminate the Plan. If EIX terminates the Plan, distributions to the Participants or their Beneficiaries shall be made on the dates on which the Participants or Beneficiaries would receive benefits hereunder without regard to the termination of the Plan except that payments may be made upon termination of the Plan if the requirements for accelerated payment under Treasury Regulation Section 1.409A-3(j)(4)(ix)(C) are satisfied.

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10.3 Amendment or Termination after Change in Control

Notwithstanding the foregoing, EIX will not amend or terminate the Plan without the prior written consent of affected Participants for a period of two calendar years following a Change in Control and will not thereafter amend or terminate the Plan in any manner which affects any Participant (or Beneficiary of a deceased Participant) who commences receiving payment of benefits under the Plan prior to the end of the two year period following a Change in Control.

10.4 Exercise of Power to Amend or Terminate

EIX's power to amend or terminate the Plan will be exercisable by the Compensation and Executive Personnel Committee of the EIX Board of Directors.

ARTICLE 11

CLAIMS AND REVIEW PROCEDURES

11.1 Claims Procedure for Claims Other Than for Vesting due to Disability

(a)Except for claims due to Disability, the Administrator will notify a Participant or his or her Beneficiary (or person submitting a claim on behalf of the Participant or Beneficiary) (a “claimant”) in writing, within 90 days after his or her written application for benefits, of his or her eligibility or noneligibility for benefits under the Plan. If the Administrator determines that a claimant is not eligible for benefits or full benefits, the notice will set forth (1) the specific reasons for the denial, (2) a specific reference to the provisions of the Plan on which the denial is based, (3) a description of any additional information or material necessary for the claimant to perfect his or her claim, and a description of why it is needed, and (4) an explanation of the Plan's claims review procedure and other appropriate information as to the steps to be taken if the claimant wishes to have the claim reviewed. If the Administrator determines that there are special circumstances requiring additional time to make a decision, the Administrator will notify the claimant of the special circumstances and the date by which a decision is expected to be made, and may extend the time for up to an additional 90-day period.

(b)If a claimant is determined by the Administrator not to be eligible for benefits, or if the claimant believes that he or she is entitled to greater or different benefits, the claimant will have the opportunity to have the claim reviewed by the Administrator by filing a petition for review with the Administrator within 60 days after receipt of the notice issued by the Administrator. Said petition will state the specific reasons which the claimant believes entitle him or her to benefits or to greater or different benefits. Within 60 days after receipt by the Administrator of the petition, the Administrator will afford the claimant (and counsel, if any) an opportunity to present his or her position to the Administrator in writing, and the claimant (or counsel) will have the right to review the pertinent documents. The Administrator will notify the claimant of its decision in writing within the 60-day period, stating specifically the basis of its decision, written in a manner calculated to be understood by the claimant and the specific provisions of the Plan on which the decision is based. If, due to special circumstances (for example, because of the need for a hearing), the 60-day period is not sufficient, the decision may be deferred for up to another 60-day period at the election of the Administrator, but notice of this deferral will be given to the claimant. In the event of the death of the Participant, the same procedures will apply to the Participant's Beneficiaries.

16

11.2 Claims Procedure for Claims due to Disability

(a)Within a reasonable period of time, but not later than 45 days after receipt of a claim due to Disability, the Administrator or its delegate shall notify the claimant of any adverse benefit determination on the claim, unless circumstances beyond the Plan's control require an extension of time for processing the claim. Except as contemplated by this Section, in no event may the extension period exceed 30 days from the end of the initial 45-day period. If an extension is necessary, the Administrator or its delegate shall provide the claimant with a written notice to this effect prior to the expiration of the initial 45-day period. The notice shall describe the circumstances requiring the extension and the date by which the Administrator or its delegate expects to render a determination on the claim. If, prior to the end of the first 30-day extension period, the Administrator or its delegate determines that, due to circumstances beyond the control of the Plan, a decision cannot be rendered within that extension period, the period for making the determination may be extended for an additional 30 days, so long as the Administrator or its delegate notifies the claimant, prior to the expiration of the first 30-day extension period, of the circumstances requiring the extension and the date as of which the Administrator or its delegate expects to render a decision. This notice of extension shall specifically describe the standards on which entitlement to a benefit is based, the unresolved issues that prevent a decision on the claim, and the additional information needed to resolve those issues, and that the claimant has at least 45 days within which to provide the specified information.

(b)In the case of an adverse benefit determination, the Administrator or its delegate shall provide to the claimant written or electronic notification setting forth in a manner calculated to be understood by the claimant (i) the specific reason or reasons for the adverse benefit determination; (ii) reference to the specific Plan provisions on which the adverse benefit determination is based; (iii) a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why the material or information is necessary; (iv) a description of the Plan's claim review procedures and the time limits applicable to such procedures, including a statement of the claimant's right to bring a civil action under Section 502(a) of ERISA following an adverse final benefit determination on review and in accordance with this Section 11.2 (v) if an internal rule, guideline, protocol or similar criterion (“internal standard”) was relied upon in making the determination, a copy of the internal standard or a statement that the internal standard shall be provided to the claimant free of charge upon request; and (vi) if the determination is based on a medical necessity or experimental treatment or similar exclusion or limit, an explanation of the scientific or clinical judgment for the determination or a statement that such explanation shall be provided free of charge upon request.

(c)If a claimant is determined by the Administrator not to be eligible for benefits, or if the claimant believes that he or she is entitled to greater or different benefits, the claimant will have the opportunity to have the claim reviewed by the Administrator by filing a petition for review with the Administrator within 180 days after receipt of the notice issued by the Administrator. Said petition will state the specific reasons which the claimant believes entitle him or her to benefits or to greater or different benefits. Within 45 days after receipt by the Administrator of the petition, the Administrator will afford the claimant (and counsel, if any) an opportunity to present his or her position to the Administrator in writing, and the claimant (or counsel) will have the right to review the pertinent documents. The Administrator will notify the claimant of its decision in writing within the 45-day period, stating specifically the basis of its decision, written in a manner calculated to be understood by the claimant and including the information described in Section 11.2(b) above. If, due to special circumstances (for example, because of the need for a hearing), the 45-day period is not sufficient, the decision may be deferred for up to another 45 day period at the election of the Administrator, but notice of this deferral will be given to the claimant. In the event of the death of the Participant, the same procedures will apply to the Participant's Beneficiaries.

17

11.3 Dispute Arbitration

Notwithstanding the foregoing, and because it is agreed that time will be of the essence in determining whether any payments are due to a claimant under the Plan, a claimant may, if he or she desires, submit any claim for payment under the Plan to arbitration. This right to select arbitration will be solely that of the claimant and the claimant may decide whether or not to arbitrate in his or her discretion. The "right to select arbitration" is not mandatory on the claimant, and the claimant may choose in lieu thereof to bring an action in an appropriate civil court. Once an arbitration is commenced, however, it may not be discontinued without the mutual consent of both parties to the arbitration. During the lifetime of the Participant only he or she can use the arbitration procedure set forth in this section.

Any claim for arbitration may be submitted as follows: if a claimant has submitted a request to be paid under the Plan and the claim is finally denied by the Administrator in whole or in part, the claim may be filed in writing with an arbitrator of the claimant's choice who is selected by the method described in the next four sentences. The first step of the selection will consist of the claimant submitting a list of five potential arbitrators to the Administrator. Each of the five arbitrators must be either (1) a member of the National Academy of Arbitrators located in the State of California or (2) a retired California Superior Court or Appellate Court judge. Within one week after receipt of the list, the Administrator will select one of the five arbitrators as the arbitrator for the dispute in question. If the Administrator fails to select an arbitrator within one week after receipt of the list, the claimant will then designate one of the five arbitrators for the dispute in question.

The arbitration hearing will be held within seven days (or as soon thereafter as possible) after the picking of the arbitrator. No continuance of said hearing will be allowed without the mutual consent of the claimant and the Administrator. Absence from or nonparticipation at the hearing by either party will not prevent the issuance of an award. Hearing procedures which will expedite the hearing may be ordered at the arbitrator's discretion, and the arbitrator may close the hearing in his or her sole discretion when he or she decides he or she has heard sufficient evidence to satisfy issuance of an award.

The arbitrator's award will be rendered as expeditiously as possible and in no event later than one week after the close of the hearing.

In the event the arbitrator finds that the Administrator or the Employer has breached the terms of the Plan, he or she will order the Employer to pay to the claimant within two business days after the decision is rendered the amount then due the claimant, plus, notwithstanding anything to the contrary in the Plan, an additional amount equal to 20% of the amount actually in dispute. The award of the arbitrator will be final and binding upon the Parties.

18

The award may be enforced in any appropriate court as soon as possible after its rendition. The Administrator will be considered the prevailing party in a dispute if the arbitrator determines (1) that neither the Administrator nor the Employer has breached the terms of the Plan and (2) the claim by the claimant was not made in good faith. Otherwise, the claimant will be considered the prevailing party. In the event that the Administrator is the prevailing party, the fee of the arbitrator and all necessary expenses of the hearing (excluding any attorneys' fees incurred by the Administrator) including the fees of a stenographic reporter, if employed, will be paid by the losing party. In the event that the claimant is the prevailing party, the fee of the arbitrator and all necessary expenses of the hearing (including all attorneys' fees incurred by the claimant in pursuing his or her claim and the fees of a stenographic reporter, if employed) will be paid by the Employer by March 15 of the year following the year in which the arbitrator determines who is the prevailing party.

Notwithstanding the foregoing, if the claim is for Disability benefits, the following rules apply: (1) the Administrator will not assert that a claimant has failed to exhaust administrative remedies if the claimant does not submit to arbitration, (2) any applicable statute of limitations or other similar defense is tolled during the time the arbitration is pending, (3) the claimant may only submit to arbitration after exhausting the claims procedures described above, and (4) no fees or costs will be imposed on the claimant as part of the arbitration (other than the claimant's attorneys' fees).

ARTICLE 12

MISCELLANEOUS

12.1 Successors

The rights and obligations of each Employer under the Plan will inure to the benefit of, and will be binding upon, the successors and assigns of the Employer.

12.2 Trust

The Employers will be responsible for the payment of all benefits under the Plan. At their discretion, the Employers may establish one or more grantor trusts for the purpose of providing for payment of benefits under the Plan. The trust or trusts may be irrevocable, but an Employer's share of the assets thereof will be subject to the claims of the Employer's creditors. Benefits paid to the Participant from any such trust will be considered paid by the Employer for purposes of meeting the obligations of the Employer under the Plan.

12.3 Employment Not Guaranteed

Nothing contained in the Plan nor any action taken hereunder will be construed as a contract of employment or as giving any Participant any right to continue in employment with the Employer or any other Affiliate.

12.4 Gender, Singular and Plural

All pronouns and variations thereof will be deemed to refer to the masculine, feminine, or neuter, as the identity of the person or persons may require. As the context may require, the singular may be read as the plural and the plural as the singular.

19

12.5 Captions

The captions of the articles and sections of the Plan are for convenience only and will not control or affect the meaning or construction of any of its provisions.

12.6 Validity

If any provision of the Plan is held invalid, void or unenforceable, the same will not affect, in any respect whatsoever, the validity of any other provisions of the Plan.

12.7 Waiver of Breach

The waiver by EIX or the Administrator of any breach of any provision of the Plan by the Participant will not operate or be construed as a waiver of any subsequent breach by the Participant.

12.8 Applicable Law

The Plan will be governed and construed in accordance with the laws of California except where the laws of California are preempted by ERISA.

12.9 Notice

Any notice or filing required or permitted to be given to the Administrator under the Plan will be sufficient if in writing and hand-delivered, or sent by first class mail to the principal office of EIX, directed to the attention of the Administrator. The notice will be deemed given as of the date of delivery, or, if delivery is made by mail, as of the date shown on the postmark.

12.10 ERISA Plan

The Plan is intended to be an unfunded plan maintained primarily to provide deferred compensation benefits for "a select group of management or highly compensated employees" within the meaning of Sections 201, 301 and 401 of ERISA and therefore to be exempt from Parts 2, 3 and 4 of Title I of ERISA. EIX is the named fiduciary.

12.11 Statutes and Regulations

Any reference to a statute or regulation herein shall include any successor to such statute or regulation.

IN WITNESS WHEREOF, EIX has adopted this amended and restated Plan effective the 24^th day of October, 2012.

EDISON INTERNATIONAL

/s/ Daryl D. David

__________________________________________

Daryl D. David

Senior Vice President, Human Resources

20

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, 2012, of Edison International;

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

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

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

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

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

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

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

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

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

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

Date: November 1, 2012

/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, 2012, 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 1, 2012

/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, 2012 (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 1, 2012

/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

Other Investments (Tables)

9 Months Ended

Sep. 30, 2012

Regulated Entity, Other Assets, Noncurrent [Abstract]

Amortized Cost and Fair Value of the Trust Investments

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, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Stocks	—	$	957	$	865	$	2,227	$	1,899
Municipal bonds	2054	520		625		654		756
U.S. government and agency securities	2042	526		516		589		580
Corporate bonds	2054	287		259		374		317
Short-term investments and receivables/payables	One-year	147		38		153		40
Total		$	2,437	$	2,303	$	3,997	$	3,592

Summary of Changes in the Fair Value of Trust

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)	2012			2011			2012			2011
Balance at beginning of period	$	3,810		$	3,657		$	3,592		$	3,480
Gross realized gains	13			46			54			81
Gross realized losses	—			(5		)	(5		)	(5		)
Unrealized gains (losses) – net	156			(305		)	272			(199		)
Other-than-temporary impairments	(7		)	(22		)	(30		)	(35		)
Interest, dividends, contributions and other	25			22			114			71
Balance at end of period	$	3,997		$	3,393		$	3,997		$	3,393

XML

Income Taxes (Details) (USD $)	3 Months Ended		9 Months Ended				9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Oct. 31, 2012 Southern California Edison Subsequent Event	Sep. 30, 2012 Homer City	Sep. 30, 2012 IRS Examination	Sep. 30, 2012 IRS Examination Southern California Edison
Effective Tax Rate
Income from continuing operations before income taxes	$ 477,000,000	$ 658,000,000	$ 781,000,000	$ 1,218,000,000
Provision for income tax at federal statutory rate of 35%	167,000,000	230,000,000	273,000,000	426,000,000
Increase (decrease) in income tax from:
State tax benefit - net of federal benefit	60,000,000	28,000,000	56,000,000	40,000,000
Production and housing credits	(12,000,000)	(12,000,000)	(48,000,000)	(48,000,000)
Property-related	(20,000,000)	(18,000,000)	(39,000,000)	(38,000,000)
Other	(14,000,000)	4,000,000	(25,000,000)	(10,000,000)
Total income tax expense from continuing operations	181,000,000	232,000,000	217,000,000	370,000,000
Effective tax rate	38.00%	35.00%	28.00%	30.00%
Federal statutory rate (as a percent)	35.00%	35.00%	35.00%	35.00%
Reconciliation of Unrecognized Tax Benefits
Beginning balance			631,000,000	565,000,000
Tax positions taken during the current year, Increases			22,000,000	53,000,000
Tax positions taken during a prior year, Increases			207,000,000	60,000,000
Tax positions taken during a prior year, Decreases			(29,000,000)	(37,000,000)
Decreases for settlements during the period			0	0
Ending balance	831,000,000	641,000,000	831,000,000	641,000,000
Unrecognized tax benefits that would impact the effective tax rate	578,000,000		578,000,000		532,000,000
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								198,000,000	95,000,000
Penalty for understatement of tax liability (as a percent)								40.00%
Tax Election at Homer City
Tax reduction due to change in tax treatment of entity							1,000,000,000
Federal and state net operating loss carryforwards and federal tax credit carryfowards							1,600,000,000
Potential earnings benefit attributable to flow through treatment of vintage year activity						$ 230,000,000

XML

Fair Value Measurements (Quantitative Information About Level 3 Fair Value Measurements) (Details) (Level 3, USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Quantitative Information About Level 3 Measurements [Line Items]
Fair Value, Assets	152
Fair Value, Liabilities	640
Electricity Options | Option Model
Quantitative Information About Level 3 Measurements [Line Items]
Fair Value, Assets	23
Fair Value, Liabilities	26
Electricity Options | Option Model | Gas Prices | Minimum
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	23.00%
Electricity Options | Option Model | Gas Prices | Maximum
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	41.00%
Electricity Options | Option Model | Gas Prices | Weighted Average
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	31.00%
Electricity Options | Option Model | Power Prices | Minimum
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	28.00%
Expected prices (in dollars per unit)	38.10
Electricity Options | Option Model | Power Prices | Maximum
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	60.00%
Expected prices (in dollars per unit)	58.80
Electricity Options | Option Model | Power Prices | Weighted Average
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	39.00%
Expected prices (in dollars per unit)	45.30
Electricity Forwards | Discounted Cash Flow
Quantitative Information About Level 3 Measurements [Line Items]
Fair Value, Assets	15
Fair Value, Liabilities	20
Electricity Forwards | Discounted Cash Flow | Power Prices | Minimum
Quantitative Information About Level 3 Measurements [Line Items]
Expected prices (in dollars per unit)	18.25
Electricity Forwards | Discounted Cash Flow | Power Prices | Maximum
Quantitative Information About Level 3 Measurements [Line Items]
Expected prices (in dollars per unit)	64.50
Electricity Forwards | Discounted Cash Flow | Power Prices | Weighted Average
Quantitative Information About Level 3 Measurements [Line Items]
Expected prices (in dollars per unit)	34.57
Electricity Congestion Contracts | Market Simulation Model
Quantitative Information About Level 3 Measurements [Line Items]
Fair Value, Assets	100
Fair Value, Liabilities	0
Electricity Congestion Contracts | Market Simulation Model | Gas Prices | Minimum
Quantitative Information About Level 3 Measurements [Line Items]
Expected prices (in dollars per unit)	2.95
Electricity Congestion Contracts | Market Simulation Model | Gas Prices | Maximum
Quantitative Information About Level 3 Measurements [Line Items]
Expected prices (in dollars per unit)	7.78
Electricity Congestion Contracts | Market Simulation Model | Power Prices | Minimum
Quantitative Information About Level 3 Measurements [Line Items]
Expected prices (in dollars per unit)	(13.90)
Electricity Congestion Contracts | Market Simulation Model | Power Prices | Maximum
Quantitative Information About Level 3 Measurements [Line Items]
Expected prices (in dollars per unit)	226.75
Electricity Congestion Contracts | Market Simulation Model | Load Forecast | Minimum
Quantitative Information About Level 3 Measurements [Line Items]
Fair value inputs, power units (in megawatts)	7,597
Electricity Congestion Contracts | Market Simulation Model | Load Forecast | Maximum
Quantitative Information About Level 3 Measurements [Line Items]
Fair value inputs, power units (in megawatts)	26,612
Electricity Congestion Contracts | Discounted Cash Flow
Quantitative Information About Level 3 Measurements [Line Items]
Fair Value, Assets	62
Fair Value, Liabilities	24
Electricity Congestion Contracts | Discounted Cash Flow | Congestion Prices | Minimum
Quantitative Information About Level 3 Measurements [Line Items]
Expected prices (in dollars per unit)	(5.39)
Electricity Congestion Contracts | Discounted Cash Flow | Congestion Prices | Maximum
Quantitative Information About Level 3 Measurements [Line Items]
Expected prices (in dollars per unit)	11.87
Electricity Congestion Contracts | Discounted Cash Flow | Congestion Prices | Weighted Average
Quantitative Information About Level 3 Measurements [Line Items]
Expected prices (in dollars per unit)	0.13
Gas Options | Option Model
Quantitative Information About Level 3 Measurements [Line Items]
Fair Value, Assets	0
Fair Value, Liabilities	6
Gas Options | Option Model | Gas Prices | Minimum
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	24.00%
Gas Options | Option Model | Gas Prices | Maximum
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	41.00%
Gas Options | Option Model | Gas Prices | Weighted Average
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	35.00%
Tolling | Option Model
Quantitative Information About Level 3 Measurements [Line Items]
Fair Value, Assets	5
Fair Value, Liabilities	617
Tolling | Option Model | Gas Prices | Minimum
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	17.00%
Tolling | Option Model | Gas Prices | Maximum
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	41.00%
Tolling | Option Model | Gas Prices | Weighted Average
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	21.00%
Tolling | Option Model | Power Prices | Minimum
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	26.00%
Expected prices (in dollars per unit)	33.20
Tolling | Option Model | Power Prices | Maximum
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	60.00%
Expected prices (in dollars per unit)	100.80
Tolling | Option Model | Power Prices | Weighted Average
Quantitative Information About Level 3 Measurements [Line Items]
Expected volatility rate (as a percent)	28.00%
Expected prices (in dollars per unit)	56.10
Netting
Quantitative Information About Level 3 Measurements [Line Items]
Fair Value, Assets	(53)
Fair Value, Liabilities	(53)

XML

Compensation and Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	1 Months Ended		3 Months Ended		9 Months Ended				3 Months Ended				9 Months Ended
	Sep. 30, 2012 Southern California Edison Work Force Reduction San Onofre	Aug. 31, 2012 Southern California Edison Work Force Reduction San Onofre Minimum positions	Aug. 31, 2012 Southern California Edison Work Force Reduction San Onofre Maximum positions	Sep. 30, 2012 Pension Plans	Sep. 30, 2011 Pension Plans	Sep. 30, 2012 Pension Plans	Sep. 30, 2011 Pension Plans	Sep. 30, 2012 Pension Plans Southern California Edison	Sep. 30, 2012 Pension Plans Previous Estimate	Sep. 30, 2012 Postretirement Benefits Other Than Pensions		Sep. 30, 2011 Postretirement Benefits Other Than Pensions		Sep. 30, 2012 Postretirement Benefits Other Than Pensions		Sep. 30, 2011 Postretirement Benefits Other Than Pensions
Pension and Other Postretirement Benefits
Plan year contributions				$ 180		$ 180			$ 286
Employer contributions						156								17
Additional plan year contributions										48				48
Requested recovery of plan contributions								168
Expense components are:
Service cost				49	43	135	129			13		11		39		33
Interest cost				49	52	147	156			30		33		90		99
Special termination benefits										3	[1]	0	[1]	3	[1]	0	[1]
Expected return on plan assets				(56)	(60)	(174)	(180)			(27)		(28)		(81)		(84)
Amortization of prior service cost (credit)				1	2	3	6			(9)		(9)		(27)		(27)
Amortization of net loss				21	6	57	18			12		9		36		27
Expense under accounting standards				64	43	168	129			22		16		60		48
Regulatory adjustment (deferred)				(57)	(6)	(3)	(18)
Total expense				7	37	165	111
Expected number of positions to be eliminated		730	1,500
Cash severance costs	$ 30

[1] Due to the reduction in the workforce at San Onofre, Edison International has incurred costs for enhanced retiree health care coverage. See below for further information.

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Variable Interest Entities (Details) (USD $)	9 Months Ended									9 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended	1 Months Ended								3 Months Ended		9 Months Ended
	Sep. 30, 2012		Dec. 31, 2011	Sep. 30, 2012 Mission Energy Holding Company	Feb. 13, 2012 Broken Bow I, LLC Agreement to Sell Ownership, Upon Satisfaction of Specific Conditions MW	Feb. 13, 2012 Crofton Bluffs Agreement to Sell Ownership, Upon Satisfaction of Specific Conditions MW	Feb. 13, 2012 Cedro Hill Wind, LLC MW	Feb. 13, 2012 Mountain Wind Power Project MW	Feb. 13, 2012 Mountain Wind Power II Project MW	Sep. 30, 2012 Capistrano Wind Partners	Feb. 13, 2012 Capistrano Wind Partners	Sep. 30, 2012 Capistrano Wind Partners Mission Energy Holding Company	Feb. 13, 2012 Capistrano Wind Partners Agreement to Sell Ownership, Upon Satisfaction of Specific Conditions	Sep. 30, 2012 SCE Trust I	Sep. 30, 2012 SCE Trust I	May 31, 2012 SCE Trust I Trust Securities	Sep. 30, 2012 SCE Trust I Trust Securities	Sep. 30, 2012 SCE Trust I Series F	May 31, 2012 SCE Trust I Series F	Sep. 30, 2012 Variable Interest Entity, Primary Beneficiary	Dec. 31, 2011 Variable Interest Entity, Primary Beneficiary	Sep. 30, 2012 Variable Interest Entity, Primary Beneficiary EMG Wind Projects MW projects	Dec. 31, 2011 Variable Interest Entity, Primary Beneficiary EMG Wind Projects projects MW	Sep. 30, 2012 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts agreements MW contracts	Sep. 30, 2011 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts	Sep. 30, 2012 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts agreements MW contracts	Sep. 30, 2011 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts
Details of projects or entities
Number of projects (in projects)																								17		17
Number of projects consolidated (in projects)																						16	13
Power generating capacity for majority interest (in megawatts)																						861	570	3,900		3,900
Summarized balance sheet information of VIEs
Current assets	$ 4,494,000,000		$ 4,484,000,000																	$ 71,000,000	$ 36,000,000
Net property, plant and equipment	4,544,000,000		4,547,000,000																	1,090,000,000	675,000,000
Other long-term assets	725,000,000		684,000,000																	73,000,000	5,000,000
Total assets	50,545,000,000		48,039,000,000																	1,234,000,000	716,000,000
Current liabilities	4,274,000,000		4,348,000,000																	40,000,000	28,000,000
Long-term debt net of current portion	13,708,000,000		13,689,000,000																	172,000,000	57,000,000
Deferred revenues																				172,000,000	69,000,000
Long-term derivative liabilities	717,000,000		547,000,000																	23,000,000	0
Other long-term liabilities	2,887,000,000		2,475,000,000																	38,000,000	22,000,000
Total liabilities	38,525,000,000		36,953,000,000																	445,000,000	176,000,000
Noncontrolling interests	1,997,000,000		1,031,000,000																	238,000,000	2,000,000
Assets serving as collateral for the debt obligations																				467,000,000	136,000,000
Sale of ownership (in megawatts)					80	40	150	61	80
Outside investors contribution										238,000,000	238,000,000		140,000,000
Ownership percentage (as a percent)												100.00%
Preferred equity interests to receive percent of cash available for distribution (as a percent)										100.00%
Cash available for distribution includes percent of tax benefits to be realized (as a percent)										90.00%
Preferred investment made				4,000,000
Note receivable from sale of project companies				107,000,000
Tax effect upon transfer of assets to Capistrano Wind Partners	21,000,000	[1]
Power purchase agreement with tolling agreement (in agreements)																								7		7
Power purchase agreement with qualified facilities (in contracts)																								10		10
Payments to unconsolidated VIEs, power purchase contracts																								158,000,000	178,000,000	292,000,000	347,000,000
Unconsolidated Trust
Security dividend rate, (as a percent)																5.625%
Liquidation value (in dollars per share)																$ 25			$ 2,500
Liquidation preference																475,000,000
Common stock														10,000	10,000	0
Common stock, percentage issued to Southern California Edison																100.00%
Preference stock																	475,000,000	475,000,000	475,000,000
Dividend income and distributions														$ 7,000,000	$ 10,000,000

[1] Common stock was reduced by $21 million during the nine months ended September 30, 2012 due to a new tax basis in the assets transferred to Capistrano Wind Partners. For further information, see Note 3.

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Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Notional Volumes of Derivative Instruments for Electric Utility Segment

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

		Economic Hedges
Commodity	Unit of Measure	September 30, 2012	December 31, 2011
Electricity options, swaps and forwards	GWh	18,304	30,881
Natural gas options, swaps and forwards	Bcf	142	300
Congestion revenue rights	GWh	140,263	166,163
Tolling arrangements	GWh	102,123	104,154

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, 2012:

	Derivative Assets									Derivative Liabilities1
(in millions)	Short-Term			Long-Term			Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	55		$	80		$	135		$	177		$	1,002		$	1,179		$	1,044
Netting and collateral	(18		)	(6		)	(24		)	(49		)	(19		)	(68		)	(44		)
Total	$	37		$	74		$	111		$	128		$	983		$	1,111		$	1,000

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, 2011:

	Derivative Assets									Derivative Liabilities
(in millions)	Short-Term			Long-Term			Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	86		$	85		$	171		$	303		$	856		$	1,159		$	988
Netting and collateral	(21		)	(15		)	(36		)	(37		)	(51		)	(88		)	(52		)
Total	$	65		$	70		$	135		$	266		$	805		$	1,071		$	936

Summarization of Economic Hedging Activities of Electric Utility

The following table summarizes the components of economic hedging activity:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Realized gains (losses)	$	(77	)	$	(58	)	$	(199	)	$	(132	)
Unrealized gains (losses)	(91		)	(110		)	(29		)	(433		)

Notional Volumes of Derivative Instruments for Competitive Power Generation Segment

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

September 30, 2012
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges	Economic Hedges		Trading Activities
Electricity	Forwards/Futures	Sales, net	GWh	5,644	58	2	—
Electricity	Forwards/Futures	Purchases, net	GWh	—	—		550
Electricity	Capacity	Purchases, net	GW-Day	—	—		97	1
Electricity	Congestion	Purchases, net	GWh	—	241	3	281,251	3
Natural gas	Forwards/Futures	Sales, net	bcf	—	—		0.4
Fuel oil	Forwards/Futures	Sales, net	barrels	—	—		100,000
Fuel oil	Forwards/Futures	Purchases, net	barrels	—	120,000		—

At September 30, 2012, EME had interest rate contracts with notional values totaling $727 million that converted floating rate LIBOR-based debt to fixed rates ranging from 0.79% to 4.29%. These contracts expire May 2013 through March 2026. In addition, at September 30, 2012, EME had forward starting interest rate contracts with notional values totaling $641 million that will convert floating rate LIBOR-based debt to fixed rates ranging from 0.7825% to 4.0025%. These contracts have effective dates beginning December 2012 through December 2021 and expire December 2013 through December 2029.

December 31, 2011
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges		Economic Hedges		Trading Activities
Electricity	Forwards/Futures	Sales, net	GWh	8,320		335	2	—
Electricity	Forwards/Futures	Purchases, net	GWh	—		—		2,926
Electricity	Capacity	Sales, net	GW-Day	61	1	—		—
Electricity	Capacity	Purchases, net	GW-Day	—		—		184	1
Electricity	Congestion	Purchases, net	GWh	—		1,261	3	230,798	3
Natural gas	Forwards/Futures	Sales, net	bcf	—		—		0.2
Fuel oil	Forwards/Futures	Purchases, net	barrels	—		240,000		—

¹  EME's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM Interconnection, LLC Reliability Pricing Model (PJM RPM) auction is not accounted for as a derivative.

²  These positions adjust financial and physical positions, or day-ahead and real-time positions, to reduce costs or increase gross margin. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.

³  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

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

September 30, 2012
	Derivative Assets									Derivative Liabilities
(in millions)	Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal			Net Assets (Liabilities)
Non-trading activities
Cash flow hedges
Commodity contracts	$	14		$	2		$	16		$	9		$	1		$	10		$	6
Interest rate contracts	—			—			—			—			125			125			(125		)
Economic hedges	25			1			26			23			1			24			2
Trading activities	321			145			466			265			98			363			103
	360			148			508			297			225			522			(14		)
Netting and collateral received1	(321		)	(105		)	(426		)	(296		)	(100		)	(396		)	(30		)
Total	$	39		$	43		$	82		$	1		$	125		$	126		$	(44	)

December 31, 2011
	Derivative Assets									Derivative Liabilities
(in millions)	Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal			Net Assets (Liabilities)
Non-trading activities
Cash flow hedges
Commodity contracts	$	40		$	1		$	41		$	2		$	—		$	2		$	39
Interest rate contracts	—			—			—			—			90			90			(90		)
Economic hedges	24			—			24			20			—			20			4
Trading activities	277			142			419			232			79			311			108
	341			143			484			254			169			423			61
Netting and collateral received1	(301		)	(81		)	(382		)	(253		)	(79		)	(332		)	(50		)
Total	$	40		$	62		$	102		$	1		$	90		$	91		$	11

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

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,
	2012						2011
(in millions)	Commodity Contracts			Interest Rate Contracts			Commodity Contracts			Interest Rate Contracts			Income Statement Location
Beginning of period derivative gains (losses)	$	35		$	(90	)	$	43		$	(16	)
Effective portion of changes in fair value	3			(35		)	2			(64		)
Reclassification to earnings	(31		)	—			(29		)	—			Competitive power generation revenue
End of period derivative gains (losses)	$	7		$	(125	)	$	16		$	(80	)

¹  Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive loss at September 30, 2012 and 2011 for commodity and interest rate contracts were $7 million and $(79) million, and $10 million and $(49) million, respectively.

Effect of Realized and Unrealized Gains (Losses) from Derivative Instruments on Competitive Power Generation Segment

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	2012		2011			2012		2011
Economic hedges	Competitive power generation revenues	$	8	$	(3	)	$	25	$	5
	Fuel	3		(3		)	2		1
Trading activities	Competitive power generation revenues	22		11			72		68

Summary of Margin and Collateral Deposits Provided to and Received from Counterparties

The following table summarizes margin and collateral deposits provided to and received from counterparties:

(in millions)	September 30, 2012		December 31, 2011
Collateral provided to counterparties:
Offset against derivative liabilities	$	54	$	53
Reflected in margin and collateral deposits	88		58
Collateral received from counterparties:
Offset against derivative assets	39		53

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Commitments and Contingencies (Contingencies) (Details) (USD $)	1 Months Ended			9 Months Ended	1 Months Ended		9 Months Ended	1 Months Ended	9 Months Ended			9 Months Ended		9 Months Ended			1 Months Ended			9 Months Ended	1 Months Ended	9 Months Ended	1 Months Ended		9 Months Ended
	Jun. 30, 2010	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 Nuclear Insurance	Oct. 31, 2011 Malibu Fire Order Instituting Investigation	Oct. 31, 2011 Alleged violations of PSD requirements and New Source Performance Standards of the CAA private_environmental_organization	Sep. 30, 2012 Edison International sites	Dec. 31, 2011 Southern California Edison	Sep. 30, 2012 Southern California Edison sites	Sep. 30, 2011 Southern California Edison	Sep. 15, 2012 Southern California Edison	Sep. 30, 2012 Southern California Edison San Onofre (nuclear) generator	Mar. 31, 2012 Southern California Edison San Onofre (nuclear) heat_transfer_tube	Sep. 30, 2012 Southern California Edison Nuclear Insurance	Sep. 30, 2012 Southern California Edison Nuclear Insurance San Onofre and Palo Verde	Sep. 30, 2012 Southern California Edison Outage, Inspection and Repair Issues San Onofre (nuclear) H	Oct. 30, 2011 Southern California Edison Malibu Fire Order Instituting Investigation	Jan. 31, 2012 Midwest Generation LLC. claims	Oct. 31, 2011 Midwest Generation LLC. claims	Sep. 30, 2012 Midwest Generation LLC. sites	Aug. 31, 2009 Midwest Generation LLC. Violation of certain operating permit requirements facilities	Sep. 30, 2012 Midwest Generation LLC. Violation of certain operating permit requirements claims	Jan. 31, 2011 Homer City Violations of the PSD and Title V provisions of the CAA owners residents	Feb. 29, 2012 Homer City Alleged violations of emissions standards and limitations under the CAA and the Pennsylvania Air Pollution Control Act	Sep. 30, 2012 SCE and other owners of San Onofre and Palo Verde Nuclear Insurance
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
Similar number of complaints previously filed asserting claims of nuisance, negligence, trespass, and strict liability that were dismissed																			2
Number of plaintiffs						4																	2
Number of prior owners of facilities																							2
Notice of intent to sue, notice time period																								60 days
Number of steam generators replaced (in generators)												4
Heat transfer tubes with water leak (in heat transfer tubes)													1
Reduced power level of operation (as a percentage)																70.00%
Term of reduced power level of operation (in months)																5 months
Authorized expenditures																525,000,000
Authorized expenditures, after adjustments for inflation																665,000,000
Ownership percentage (as a percent)												78.21%
Costs incurred to date																594,000,000
Construction work in progress																95,000,000
Authorized expenditures by authoritative body, market costs incurred																221,000,000
Annual revenue requirement request, nuclear fuel-related and decommissioning costs																170,000,000
Incremental inspection and repair costs																96,000,000
Collected revenue, based on current authorized revenue requirements																625,000,000
Annual revenue requirement request																820,000,000
Direct operating and maintenance costs, depreciation and return on investment																650,000,000
Rate base																1,200,000,000
Net investment and inventory associated with plant																2,100,000,000
Term of outage for which notification is required (in months)																9 months
Required term, from notice of investigation to remove revenue requirements from customer rates																45 days
Continuous hours of operation, after which rates may be readjusted																100
Steam generators, warranted period																20 years
MHI's limited liability under purchase agreement, excluding consequential damages																138,000,000
Invoiced amount to MHI																45,000,000
Damages sought					99,000,000			98,000,000									50,000,000
Identified material sites for environmental remediation (in number of sites)							27		25											2
Identified material sites, minimum amount of upper end of range of costs							1,000,000
Minimum liability for environmental remediation							121,000,000		113,000,000			78,000,000
Immaterial sites for environmental remediation (in number of sites)									33
Immaterial sites, range of liability, minimum									3,000,000
Environmental remediation liability									116,000,000
Regulatory assets		5,677,000,000	5,466,000,000						113,000,000
Portion of recorded liability recoverable from incentive mechanism									31,000,000
Percentage of environmental remediation costs recoverable through an incentive mechanism (as a percent)									90.00%
Liability incurred at majority of the remaining sites through customer rates									82,000,000
Environmental remediation costs to be recovered (as a percent)									100.00%
Amount that cleanup costs could exceed recorded liability for identified material sites									185,000,000
Amount that cleanup costs could exceed recorded liability for immaterial sites									6,000,000
Maximum expected period for cleanup of identified sites (in years)									30 years
Expected annual environmental remediation costs, low end of range									7,000,000
Expected annual environmental remediation costs, high end of range									14,000,000
Environmental remediation costs									5,000,000	9,000,000
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
Loss limit, property damage insurance, federal minimum requirement															1,100,000,000
Limit on assessment of retrospective premium adjustments, per year, approximate														49,000,000
Insurance coverage for wildfire liabilities Limit											550,000,000
Self insurance retention per wildfire occurence											10,000,000
Amount of damages, decision by US Court of Federal Claims, spent nuclear fuel litigation	$ 142,000,000

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Discontinued Operations

9 Months Ended

Sep. 30, 2012

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

Discontinued Operations

On September 21, 2012, Homer City and an affiliate of GECC entered into the Homer City MTA for the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities. On October 3, 2012, GECC entered into a Plan Support Agreement ("the PSA") with the holders of approximately 76% of the outstanding principal amount of the secured lease obligation bonds issued by Homer City Funding, LLC as part of the original sale-leaseback transaction. Under the PSA, the parties committed to support and implement a reorganization plan of Homer City Funding, LLC and to solicit votes on a prepackaged plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 5, 2012, GECC commenced the solicitation. Homer City Funding, LLC is an affiliate of GECC and not related to Homer City or any other EME affiliate.

Completion of the Homer City MTA is subject to the satisfaction of a number of closing conditions, including the successful restructuring and reorganization of Homer City Funding, LLC and receipt of the regulatory approvals required for the transfer of the Homer City plant to GECC. If an agreement to modify the terms of the bonds is not approved and consummated or if other closing conditions of the Homer City MTA are not met, Homer City may become the subject of bankruptcy proceedings.

EME recorded an impairment charge of $1.03 billion related to Homer City's long-lived assets during the fourth quarter of 2011. Beginning in the third quarter of 2012, Homer City met the definition of a discontinued operation and was classified separately in Edison International's consolidated financial statements. EME recorded a $113 million charge ($68 million after tax) to write down assets held for sale to net realizable value during the third quarter of 2012.

Summarized results of discontinued operations are as follows:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Total operating revenues	$	121		$	159		$	303		$	409
Total operating expenses	(138		)	(134		)	(385		)	(409		)
Asset impairment and other charges	(113		)	—			(134		)	—
Other income (expense)	5			2			7			(1		)
Income (loss) before income taxes	(125		)	27			(209		)	(1		)
Provision (benefit) for income taxes	(49		)	12			(80		)	2
Income (loss) from operations of discontinued operations	$	(76	)	$	15		$	(129	)	$	(3	)

The assets and liabilities associated with the discontinued operations are segregated on the consolidated balance sheets at September 30, 2012 and December 31, 2011. The carrying amount of the major components of asset and liability of discontinued operations are as follows:

(in millions)	September 30, 2012			December 31, 2011
Cash and cash equivalents	$	55		$	79
Other current assets	114			128
Carrying value adjustment	(108		)	—
Total current assets	61			207
Other long-term assets	—			45
Assets of discontinued operations	61			252
Total current liabilities	61			27
Other long-term liabilities	—			9
Liabilities of discontinued operations	$	61		$	36

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Debt and Credit Agreements (Details) (USD $) In Millions, unless otherwise specified						1 Months Ended				1 Months Ended											3 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 Southern California Edison	Dec. 31, 2011 Southern California Edison	Sep. 30, 2012 Edison Mission Energy Short-term Debt [Member]	Mar. 30, 2012 Broken Bow and Crofton Bluffs Wind Projects	Sep. 30, 2012 Big Sky	Oct. 31, 2009 Big Sky MW	Mar. 31, 2012 First and refunding mortgage bonds Southern California Edison	Dec. 31, 2011 Term Loan Tapestry Wind, LLC	Oct. 31, 2009 Vendor financing loan due 2014 Big Sky	Sep. 30, 2012 Letters of Credit	Sep. 30, 2012 Letters of Credit Southern California Edison	Sep. 30, 2012 Letters of Credit Edison Mission Energy	Sep. 30, 2012 Letters of Credit Subsidiaries	Sep. 30, 2012 Letters of Credit Walnut Creek credit facility	Sep. 30, 2012 Revolving credit facility Southern California Edison	Feb. 29, 2012 Revolving credit facility Edison Mission Energy	Sep. 30, 2012 Revolving credit facility Midwest Generation LLC.	Mar. 31, 2012 Revolving credit facility terminating June 2014 Edison Mission Energy	Sep. 30, 2012 Revolving credit facility maturing in May 2017	Dec. 31, 2011 Revolving credit facility maturing in May 2017
Debt Instrument:
Construction loans						$ 79
Long-term debt - Gross									400	214
Vendor financing max borrowing amount											206
Term of amortizing loan (in years)						15 years				10 years											5 years
Letter of credit facilities						13
Working capital facilities						6
Floating interest rate received						LIBOR
Variable rate, spread (as a percent)						2.875%
Variable rate, increase rate after third, sixth, ninth and twelfth years (as a percent)						0.125%
Construction loan, amount outstanding					21
Interest rate on debt (as a percent)									4.05%
Cash proceeds received from issuance of debt										97
Outstanding short-term debt	429	429	380	419																	28	10
Short-term debt, weighted average interest rate (as a percent)			0.43%	0.44%																	1.52%	0.66%
Credit facility																	2,750	564	500	100	1,250
Outstanding credit facility													(196)
Letter of credit expiration date																	5 years
Standby letters of credit												154		51	103	30
Standby letters of credit expiring in 2012															2
Standby letters of credit expiring in 2013														48	49
Standby letters of credit expiring in 2014														3
Standby letters of credit expiring in 2017															21
Standby letters of credit expiring in 2018															18
Standby letters of credit expiring in 2021															13
Outstanding letters of credit					6
Power generating capacity for majority interest (in megawatts)								240
Debt instrument, final maturity period											5 years
Investments in unconsolidated affiliates	$ 544	$ 525					$ 130

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Business Segments (Tables)

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Information Related to Business Segments

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)	2012			2011			2012			2011
Operating Revenue:
Electric utility	$	3,731		$	3,386		$	8,794		$	8,063
Competitive power generation	340			437			1,009			1,277
Parent and other2	(1		)	(1		)	(3		)	(3		)
Consolidated Edison International	$	4,070		$	3,822		$	9,800		$	9,337
Net Income (Loss) attributable to Edison International:
Electric utility	$	363		$	406		$	736		$	838
Competitive power generation1	(137		)	33			(331		)	(17		)
Parent and other2	(36		)	(13		)	(48		)	(19		)
Consolidated Edison International	$	190		$	426		$	357		$	802

Segment balance sheet information was:

(in millions)	September 30, 2012			December 31, 2011
Total Assets:
Electric utility	$	43,059		$	40,315
Competitive power generation	7,934			8,392
Parent and other2	(448		)	(668		)
Consolidated Edison International	$	50,545		$	48,039

¹  Includes earnings (losses) from discontinued operations of $(76) million and $15 million for the three months ended September 30, 2012 and 2011, respectively, and $(129) million and $(3) million for the nine months ended September 30, 2012 and 2011, 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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Supplemental Cash Flows Information (Tables)

9 Months Ended

Sep. 30, 2012

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

	Nine months ended September 30,
(in millions)	2012			2011
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	550		$	529
Tax refunds – net	(71		)	(330		)
Noncash investing and financing activities:
Details of debt exchange:
Pollution-control bonds redeemed	$	—		$	(86	)
Pollution-control bonds issued	—			86
Dividends declared but not paid:
Common stock	$	106		$	104
Preferred and preference stock	6			12

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Derivative Instruments and Hedging Activities (Notional Values) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2011
Edison Mission Energy | Interest Rate Contracts
Derivatives
Notional Amount of Interest Rate Derivatives	$ 727		$ 644
Derivative, Lower Variable Interest Rate Range	0.79%		0.79%
Derivative, Higher Variable Interest Rate Range	4.29%		4.29%
Edison Mission Energy | Foward Starting Interest Rate Contracts
Derivatives
Notional Amount of Interest Rate Derivatives	$ 641		$ 506
Derivative, Lower Variable Interest Rate Range	0.7825%
Derivative, Higher Variable Interest Rate Range	4.0025%
Edison Mission Energy | Foward Starting Interest Rate Contracts | Convert Floating Rate Debt to Fixed 3.5429% Debt [Member]
Derivatives
Derivative, Lower Variable Interest Rate Range			3.5429%
Edison Mission Energy | Foward Starting Interest Rate Contracts | Convert Floating Rate Debt to Fixed 3.57% Debt [Member]
Derivatives
Derivative, Higher Variable Interest Rate Range			3.57%
Edison Mission Energy | Foward Starting Interest Rate Contracts | Convert Floating Rate Debt to Fixed 4.0025% Debt [Member]
Derivatives
Derivative, Higher Variable Interest Rate Range			4.0025%
Electric Utility | Electricity options, swaps and forwards (GWh) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	18,304.0		30,881.0
Electric Utility | Natural gas options, swaps and forwards (bcf) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	142.0		300.0
Electric Utility | Congestion revenue rights (GWh) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	140,263.0		166,163.0
Electric Utility | Tolling arrangements (GWh) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	102,123.0		104,154.0
Competitive Power Generation | Electricity Forwards/Futures, Sales (GWh) | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	5,644.0		8,320.0
Competitive Power Generation | Electricity Forwards/Futures, Sales (GWh) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	58	[1]	335.0	[1]
Competitive Power Generation | Electricity Forwards/Futures, Sales (GWh) | Trading activities
Derivatives
Notional Volumes of Derivative Instruments	0		0
Competitive Power Generation | Electricity Forwards/Futures, Purchases (GWh) | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0		0
Competitive Power Generation | Electricity Forwards/Futures, Purchases (GWh) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0		0
Competitive Power Generation | Electricity Forwards/Futures, Purchases (GWh) | Trading activities
Derivatives
Notional Volumes of Derivative Instruments	550.0		2,926.0
Competitive Power Generation | Electricity Capacity, Sales (GW-Day) | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments			61	[2]
Competitive Power Generation | Electricity Capacity, Sales (GW-Day) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments			0
Competitive Power Generation | Electricity Capacity, Sales (GW-Day) | Trading activities
Derivatives
Notional Volumes of Derivative Instruments			0
Competitive Power Generation | Electricity Capacity, Purchases (GW-Day) | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0		0
Competitive Power Generation | Electricity Capacity, Purchases (GW-Day) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0		0
Competitive Power Generation | Electricity Capacity, Purchases (GW-Day) | Trading activities
Derivatives
Notional Volumes of Derivative Instruments	97	[2]	184.0	[2]
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	241.0	[3]	1,261.0	[3]
Competitive Power Generation | Electricity Congestion, Purchases (GWh) | Trading activities
Derivatives
Notional Volumes of Derivative Instruments	281,251.0	[3]	230,798.0	[3]
Competitive Power Generation | Natural Gas Forwards/Futures, Sales (bcf) | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0		0
Competitive Power Generation | Natural Gas Forwards/Futures, Sales (bcf) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0		0
Competitive Power Generation | Natural Gas Forwards/Futures, Sales (bcf) | Trading activities
Derivatives
Notional Volumes of Derivative Instruments	0.4		0.2
Competitive Power Generation | Fuel Oil Forwards/Futures, Sales (barrels) | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0
Competitive Power Generation | Fuel Oil Forwards/Futures, Sales (barrels) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	0
Competitive Power Generation | Fuel Oil Forwards/Futures, Sales (barrels) | Trading activities
Derivatives
Notional Volumes of Derivative Instruments	100,000.0
Competitive Power Generation | Fuel Oil Forwards/Futures, Purchases (barrels) | Cash flow hedges
Derivatives
Notional Volumes of Derivative Instruments	0		0
Competitive Power Generation | Fuel Oil Forwards/Futures, Purchases (barrels) | Economic hedges
Derivatives
Notional Volumes of Derivative Instruments	120,000.0		240,000.0
Competitive Power Generation | Fuel Oil Forwards/Futures, Purchases (barrels) | Trading activities
Derivatives
Notional Volumes of Derivative Instruments	0		0

[1] These positions adjust financial and physical positions, or day-ahead and real-time positions, to reduce costs or increase gross margin. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.

[2] EME's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM Interconnection, LLC Reliability Pricing Model (PJM RPM) auction is not accounted for as a derivative.

[3] 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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EME Liquidity and Restructuring Activities (Details) (USD $)	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2011	Dec. 31, 2010
Restructuring Cost and Reserve [Line Items]
Cash and cash equivalents	$ 1,080,000,000	$ 1,390,000,000	$ 1,280,000,000	$ 1,261,000,000
Edison Mission Energy
Restructuring Cost and Reserve [Line Items]
Corporate cash and cash equivalents, without contractual dividend restrictions	627,000,000
Unsecured notes outstanding	3,700,000,000
Unsecured bonds, general grace period (in days)	30 days
Investment in consolidated subsidiary Edison Mission Energy	1,240,000,000
Accumulated other comprehensive loss, due to deconsolidation	128,000,000
Edison Mission Energy | Unsecured Notes Maturing June 2013
Restructuring Cost and Reserve [Line Items]
Unsecured notes outstanding	500,000,000
Edison Mission Energy | Bonds due 2017, 2019 and 2027 | Interest Payment Due November 15, 2012
Restructuring Cost and Reserve [Line Items]
Interest payments due	97,000,000
Midwest Generation LLC.
Restructuring Cost and Reserve [Line Items]
Cash and cash equivalents	$ 142,000,000

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Regulatory Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Regulatory Assets
Regulatory Assets, Current	$ 250	$ 494
Regulatory Asset, Long-term	5,677	5,466
Total Regulatory Assets	5,927	5,960
Regulatory Liabilities
Regulatory Liabilities, Current	493	670
Regulatory Liabilities, Long-term	5,249	4,670
Total Regulatory Liabilities	5,742	5,340
Regulatory Balancing Accounts, Assets
Regulatory Assets
Regulatory Assets, Current	108	223
Regulatory Asset, Long-term	102	69
Energy Derivatives
Regulatory Assets
Regulatory Assets, Current	141	264
Regulatory Asset, Long-term	573	487
Other
Regulatory Assets
Regulatory Assets, Current	1	7
Regulatory Asset, Long-term	335	298
Regulatory Liabilities
Regulatory Liabilities, Current	15	9
Regulatory Liabilities, Long-term	7	4
Deferred Income Taxes - Net
Regulatory Assets
Regulatory Asset, Long-term	2,148	2,020
Pensions and Other Postretirement Benefits
Regulatory Assets
Regulatory Asset, Long-term	1,657	1,703
Unamortized Investments - Net
Regulatory Assets
Regulatory Asset, Long-term	484	484
Unamortized Loss on Reacquired Debt
Regulatory Assets
Regulatory Asset, Long-term	233	249
Nuclear-Related Investment - Net
Regulatory Assets
Regulatory Asset, Long-term	145	156
Regulatory Balancing Accounts, Liabilities
Regulatory Liabilities
Regulatory Liabilities, Current	478	661
Regulatory Liabilities, Long-term	1,119	864
Costs of Removal
Regulatory Liabilities
Regulatory Liabilities, Long-term	2,745	2,697
Asset Retirement Obligations
Regulatory Liabilities
Regulatory Liabilities, Long-term	$ 1,378	$ 1,105

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended													3 Months Ended				9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2011	Dec. 31, 2010	Sep. 30, 2012 Stocks	Dec. 31, 2011 Stocks	Sep. 30, 2012 Municipal bonds	Dec. 31, 2011 Municipal bonds	Sep. 30, 2012 U.S. government and agency securities	Dec. 31, 2011 U.S. government and agency securities	Sep. 30, 2012 Corporate bonds	Dec. 31, 2011 Corporate bonds	Sep. 30, 2012 Level 3		Sep. 30, 2011 Level 3		Sep. 30, 2012 Level 3		Sep. 30, 2011 Level 3		Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1		Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1 Electricity	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1 Electricity	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1 Natural Gas	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1 Natural Gas	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1 Fuel Oil	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1 Fuel Oil	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1 Tolling	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1 Tolling	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1 Interest rate contracts	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1 Interest rate contracts	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1 Stocks		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1 Stocks		Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1 Municipal bonds	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1 Municipal bonds	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1 U.S. government and agency securities	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1 U.S. government and agency securities	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1 Corporate bonds		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1 Corporate bonds		Sep. 30, 2012 Fair Value, Measurements, Recurring Level 1 Short-term investments, primarily cash equivalents		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 1 Short-term investments, primarily cash equivalents	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2		Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2 Electricity	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2 Electricity	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2 Natural Gas	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2 Natural Gas	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2 Fuel Oil	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2 Fuel Oil	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2 Tolling	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2 Tolling	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2 Interest rate contracts	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2 Interest rate contracts	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2 Stocks		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2 Stocks		Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2 Municipal bonds	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2 Municipal bonds	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2 U.S. government and agency securities	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2 U.S. government and agency securities	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2 Corporate bonds		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2 Corporate bonds		Sep. 30, 2012 Fair Value, Measurements, Recurring Level 2 Short-term investments, primarily cash equivalents		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 2 Short-term investments, primarily cash equivalents	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3		Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3 Electricity	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3 Electricity	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3 Natural Gas	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3 Natural Gas	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3 Fuel Oil	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3 Fuel Oil	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3 Tolling	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3 Tolling	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3 Interest rate contracts	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3 Interest rate contracts	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3 Stocks		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3 Stocks		Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3 Municipal bonds	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3 Municipal bonds	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3 U.S. government and agency securities	Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3 U.S. government and agency securities	Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3 Corporate bonds		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3 Corporate bonds		Sep. 30, 2012 Fair Value, Measurements, Recurring Level 3 Short-term investments, primarily cash equivalents		Dec. 31, 2011 Fair Value, Measurements, Recurring Level 3 Short-term investments, primarily cash equivalents	Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral		Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral Electricity		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral Electricity		Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral Natural Gas		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral Natural Gas		Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral Fuel Oil		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral Fuel Oil		Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral Tolling		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral Tolling		Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral Interest rate contracts		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral Interest rate contracts		Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral Stocks		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral Stocks		Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral Municipal bonds		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral Municipal bonds		Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral U.S. government and agency securities		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral U.S. government and agency securities		Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral Corporate bonds		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral Corporate bonds		Sep. 30, 2012 Fair Value, Measurements, Recurring Netting and Collateral Short-term investments, primarily cash equivalents		Dec. 31, 2011 Fair Value, Measurements, Recurring Netting and Collateral Short-term investments, primarily cash equivalents		Sep. 30, 2012 Fair Value, Measurements, Recurring Total		Dec. 31, 2011 Fair Value, Measurements, Recurring Total		Sep. 30, 2012 Fair Value, Measurements, Recurring Total Electricity	Dec. 31, 2011 Fair Value, Measurements, Recurring Total Electricity	Sep. 30, 2012 Fair Value, Measurements, Recurring Total Natural Gas	Dec. 31, 2011 Fair Value, Measurements, Recurring Total Natural Gas	Sep. 30, 2012 Fair Value, Measurements, Recurring Total Fuel Oil	Dec. 31, 2011 Fair Value, Measurements, Recurring Total Fuel Oil	Sep. 30, 2012 Fair Value, Measurements, Recurring Total Tolling	Dec. 31, 2011 Fair Value, Measurements, Recurring Total Tolling	Sep. 30, 2012 Fair Value, Measurements, Recurring Total Interest rate contracts	Dec. 31, 2011 Fair Value, Measurements, Recurring Total Interest rate contracts	Sep. 30, 2012 Fair Value, Measurements, Recurring Total Stocks		Dec. 31, 2011 Fair Value, Measurements, Recurring Total Stocks		Sep. 30, 2012 Fair Value, Measurements, Recurring Total Municipal bonds	Dec. 31, 2011 Fair Value, Measurements, Recurring Total Municipal bonds	Sep. 30, 2012 Fair Value, Measurements, Recurring Total U.S. government and agency securities	Dec. 31, 2011 Fair Value, Measurements, Recurring Total U.S. government and agency securities	Sep. 30, 2012 Fair Value, Measurements, Recurring Total Corporate bonds		Dec. 31, 2011 Fair Value, Measurements, Recurring Total Corporate bonds		Sep. 30, 2012 Fair Value, Measurements, Recurring Total Short-term investments, primarily cash equivalents		Dec. 31, 2011 Fair Value, Measurements, Recurring Total Short-term investments, primarily cash equivalents
Assets at Fair Value
Money market funds	$ 933			$ 1,300																			$ 933	[1]	$ 1,293	[1]																										$ 0	[1]	$ 0	[1]																										$ 0	[1]	$ 0	[1]																										$ 0	[1],[2]	$ 0	[1],[2]																																									$ 933	[1]	$ 1,293	[1]
Derivative contracts																							3		8		0	0	1	4	2	4	0	0																		85		70		85	65	0	5	0	0	0	0																		152		228		148	218	0	0	0	0	4	10																		(47)	[2]	(69)	[2]	(44)	[2]	(58)	[2]	(1)	[2]	(7)	[2]	(2)	[2]	(4)	[2]	0	[2]	0	[2]																									193		237		189	225	0	2	0	0	4	10
Long-term disability plan																							8		8																											0		0																											0		0																											0	[2]	0	[2]																																									8		8
Nuclear decommissioning trusts	3,997	3,393	3,810	3,592	3,657	3,480	2,227	1,899	654	756	589	580	374	317									2,694		2,332												2,227	[3]	1,899	[3]	0	0	467	433	0	[4]	0	[4]	0	[5]	0	1,295		1,235												0	[3]	0	[3]	654	756	122	147	374	[4]	317	[4]	145	[5]	15	0		0												0	[3]	0	[3]	0	0	0	0	0	[4]	0	[4]	0	[5]	0	0	[2]	0	[2]																					0	[2],[3]	0	[2],[3]	0	[2]	0	[2]	0	[2]	0	[2]	0	[2],[4]	0	[2],[4]	0	[2],[5]	0	[2]	3,989		3,567												2,227	[3]	1,899	[3]	654	756	589	580	374	[4]	317	[4]	145	[5]	15
Total assets															152				152				3,638	[6]	3,641	[6]																										1,380	[6]	1,305	[6]																										152	[6]	228	[6]																										(47)	[2],[6]	(69)	[2],[6]																																									5,123	[6]	5,105	[6]
Liabilities at Fair Value
Derivative contracts																							1		0		0	0	1	0			0	0	0	0																123		244		8	10	115	234			0	0	125	90																640		551		17	77	6	23			617	451	0	0																(63)	[2]	(69)	[2]	(15)	[2]	(17)	[2]	(48)	[2]	(52)	[2]					0	[2]	0	[2]	0	[2]	0	[2]																					701		726		10	70	74	205			617	451	125	90
Total liabilities															640				640				1		0																											248		334																											640		551																											(63)	[2]	(69)	[2]																																									826		816
Net assets (liabilities)																							3,637		3,641																											1,132		971																											(488)		(323)																											16	[2]	0	[2]																																									4,297		4,289
Percentage of equity investments located in the United States (as a percent)	67.00%			70.00%
Collateralized mortgage obligations and other asset backed securities	42			22
Receivables (payables) net related to investments	8			25
Cash surrender value of life insurance	70			81
Leveraged leases	77			118
Fair Value Disclosures Level 3
Fair value of net asset (liabilities) at beginning of period															(343)		(275)		(323)		97
Total realized/unrealized gains (losses):
Included in earnings															12	[7]	(4)	[7]	20	[7]	14	[7]
Included in regulatory assets and liabilities															(124)	[8],[9]	162	[8],[9]	(140)	[8],[9]	(220)	[8],[9]
Included in accumulated other comprehensive income															(1)	[10]	1	[10]	1	[10]	(2)	[10]
Purchases															41		24		111		51
Settlements															(73)		(8)		(106)		(38)
Transfers into Level 3															0		0		0		0
Transfers out of Level 3															0	[11]	0	[11]	(51)	[11]	(2)	[11]
Fair value of net liabilities at end of period															(488)		(100)		(488)		(100)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period															(173)	[12]	(110)	[12]	(181)	[12]	(425)	[12]
Unrealized gain (loss) related to Level 3 financial instruments reported within competitive power generation revenue	$ (7)	$ 7

[1] Money market funds are included in cash and cash equivalents and restricted cash and cash equivalents on Edison International's consolidated balance sheets.

[2] 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.

[3] Approximately 67% and 70% of the equity investments were located in the United States at September 30, 2012 and December 31, 2011, respectively.

[4] At September 30, 2012 and December 31, 2011, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $42 million and $22 million, respectively.

[5] Excludes net receivables of $8 million and $25 million at September 30, 2012 and December 31, 2011, respectively, of interest and dividend receivables as well as receivables and payables related to pending securities sales and purchases.

[6] Excludes other investments of $70 million and $81 million at September 30, 2012 and December 31, 2011, respectively, primarily related to the cash surrender value of company owned life insurance investments which are used to fund certain executive benefits including deferred compensation. Also excludes other investments of $77 million and $118 million at September 30, 2012 and December 31, 2011, respectively, primarily related to leveraged leases.

[7] Reported in "Competitive power generation" revenue on Edison International's consolidated statements of income.

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

[9] Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.

[10] Included in reclassification adjustments in Edison International's consolidated statements of other comprehensive income.

[11] Transfers out of Level 3 into Level 2 occurred due to significant observable inputs becoming available as the transactions near maturity.

[12] Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income was a loss of $7 million for three months ended September 30, 2012, and a gain of $7 million for the nine months ended September 30, 2011. The remainder of the unrealized losses relate to SCE. See 2 above.

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Consolidated Statements of Changes in Equity

9 Months Ended

Sep. 30, 2012

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, 2012.

	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, 2011	$	2,360		$	(139	)	$	7,834		$	10,055		$	2		$	1,029		$	11,086
Net income	—			—			357			357			12			66			435
Other comprehensive loss	—			(29		)	—			(29		)	—			—			(29		)
Contributions from noncontrolling interests1	—			—			—			—			238			—			238
Transfer of assets to Capistrano Wind Partners2	(21		)	—			—			(21		)	—			—			(21		)
Common stock dividends declared ($0.975 per share)	—			—			(318		)	(318		)	—			—			(318		)
Dividends, distributions to noncontrolling interests and other	—			—			—			—			(14		)	(66		)	(80		)
Stock-based compensation and other	19			—			(64		)	(45		)	—			—			(45		)
Noncash stock-based compensation and other	27			—			(2		)	25			—			—			25
Issuance of preference stock	—			—			—			—			—			804			804
Redemption of preference stock	—			—			(1		)	(1		)	—			(74		)	(75		)
Balance at September 30, 2012	$	2,385		$	(168	)	$	7,806		$	10,023		$	238		$	1,759		$	12,020

¹  Funds contributed by third-party investors related to the Capistrano Wind equity capital raise are reported in noncontrolling interest. For further information, see Note 3.

²  Common stock was reduced by $21 million during the nine months ended September 30, 2012 due to a new tax basis in the assets transferred to Capistrano Wind Partners. For further information, see Note 3.

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 interest1	(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.

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Other Investments (Amortized Cost and Fair Value of Nuclear Decommissioning Trusts) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2011	Dec. 31, 2010
Fair Value Disclosures:
Period of reviewing contributions from decommissioning trusts (in years)			3 years
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	$ 2,437,000,000		$ 2,437,000,000			$ 2,303,000,000
Fair Value	3,997,000,000	3,393,000,000	3,997,000,000	3,393,000,000	3,810,000,000	3,592,000,000	3,657,000,000	3,480,000,000
Proceeds from sale of securities	428,000,000	962,000,000	1,525,000,000	2,108,000,000
Unrealized holding gains, net of losses	1,600,000,000		1,600,000,000			1,300,000,000
Stocks
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments (in years)			0
Amortized Cost	957,000,000		957,000,000			865,000,000
Fair Value	2,227,000,000		2,227,000,000			1,899,000,000
Municipal bonds
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments (in years)			2054
Amortized Cost	520,000,000		520,000,000			625,000,000
Fair Value	654,000,000		654,000,000			756,000,000
U.S. government and agency securities
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments (in years)			2042
Amortized Cost	526,000,000		526,000,000			516,000,000
Fair Value	589,000,000		589,000,000			580,000,000
Corporate bonds
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments (in years)			2054
Amortized Cost	287,000,000		287,000,000			259,000,000
Fair Value	374,000,000		374,000,000			317,000,000
Short-term investments and receivables/payables
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments (in years)			One-year
Amortized Cost	147,000,000		147,000,000			38,000,000
Fair Value	153,000,000		153,000,000			40,000,000
Southern California Edison
Fair Value Disclosures:
Contributions received for decommissioning trusts			$ 23,000,000

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Summary of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012 segment	Dec. 31, 2011
Summary of Significant Accounting Policies [Line Items]
Number of segments for financial reporting purposes	2
Cash Equivalents
Money market funds	$ 933	$ 1,300
Maximum maturity period of cash equivalent investments (in months)	3 months
Cash reclassified to accounts payable under cash management program	234	220
Restricted Cash and Deposits
Restricted deposits	89	25
Inventory
Coal, gas, fuel oil and other raw materials	138	143
Spare parts, materials and supplies	370	376
Total inventory	508	519
Edison Mission Energy | Letters of Credit
Restricted Cash and Deposits
Restricted deposits	48
Electric Utility
Summary of Significant Accounting Policies [Line Items]
Supply of electricity, area covered (square mile)	50,000
Wind Financing
Restricted Cash and Deposits
Restricted cash and cash equivalents	$ 97	$ 97

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

Inventory Components

Inventory consisted of the following:

(in millions)	September 30, 2012		December 31, 2011
Coal, gas, fuel oil and other raw materials	$	138	$	143
Spare parts, materials and supplies	370		376
Total inventory	$	508	$	519

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)	2012		2011		2012		2011
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	266	$	411	$	486	$	805
Participating securities dividends	—		—		—		—
Income from continuing operations available to common shareholders	$	266	$	411	$	486	$	805
Weighted average common shares outstanding	326		326		326		326
Basic earnings per share – continuing operations	$	0.81	$	1.26	$	1.49	$	2.47
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	266	$	411	$	486	$	805
Income impact of assumed conversions	—		2		1		3
Income from continuing operations available to common shareholders and assumed conversions	$	266	$	413	$	487	$	808
Weighted average common shares outstanding	326		326		326		326
Incremental shares from assumed conversions	3		3		2		3
Adjusted weighted average shares – diluted	329		329		328		329
Diluted earnings per share – continuing operations	$	0.81	$	1.25	$	1.48	$	2.46

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

Cash Equivalents

Cash Equivalents

Cash equivalents included investments in money market funds totaling $933 million and $1.3 billion at September 30, 2012 and December 31, 2011, respectively. Generally, the carrying value of cash equivalents equals the fair value, as these investments have original 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 $234 million and $220 million of checks issued, but not yet paid by the financial institution, from cash to accounts payable at September 30, 2012 and December 31, 2011, respectively.

Restricted Cash and Cash Equivalents

Restricted Cash and Cash Equivalents, and Restricted Deposits

Restricted cash and cash equivalents at September 30, 2012 and December 31, 2011 included $97 million received from a wind project financing that was held in escrow at those dates. At September 30, 2012, restricted deposits included $48 million to support outstanding letters of credit issued under EME's letter of credit facilities.

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.

Revenue Recognition

Revenue Recognition

Electric Utility Revenue

Operating revenue is recognized when electricity is delivered and includes amounts for services rendered but unbilled at the end of each reporting period. During the first nine months of 2012, pending the outcome of the 2012 GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement included in customer rates. A GRC memorandum account has been established for SCE, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.

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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Commitments and Contingencies (Commitments) (Details) (USD $)						1 Months Ended			1 Months Ended		9 Months Ended
	Sep. 30, 2012 Southern California Edison Environmental Indemnities	Sep. 30, 2012 Southern California Edison Operating Leases, Purchase Power Agreements	Sep. 30, 2012 Southern California Edison Power Purchase Contracts	Sep. 30, 2012 Edison Mission Group	Sep. 30, 2012 Edison Mission Energy Indemnities under International Asset Sale Agreements	Oct. 31, 2012 Homer City	Apr. 30, 2012 Homer City	Sep. 30, 2012 Homer City Senior Rent Reserve Letter of Credit	Feb. 20, 2003 Midwest Generation LLC. Environmental Indemnities under Acquisition Agreement	Sep. 30, 2012 Midwest Generation LLC. Environmental Indemnities under Acquisition Agreement claims	Sep. 30, 2012 Midwest Generation LLC. Coal Transportation Agreements
Third-Party Power Purchase Agreements
Estimated additional commitments, 2014			$ 17,000,000
Estimated additional commitments, 2015		21,000,000	43,000,000
Estimated additional commitments, 2016		45,000,000	66,000,000
Estimated additional commitments, thereafter		942,000,000	970,000,000
Coal Transportation Commitments
Coal transportation agreements, aggregate											2,300,000,000
Coal transportation agreements, remainder of 2012											118,000,000
Coal transportation agreements, 2013											292,000,000
Coal transportation agreements, 2014											286,000,000
Coal transportation agreements, 2015											260,000,000
Coal transportation agreements, 2016											260,000,000
Coal transportation agreements, thereafter											1,100,000,000
Firm commitments for capital expenditures, remainder of 2012				92,000,000
Firm commitments for capital expenditures, 2013				44,000,000
Firm commitments for capital expenditures, 2015				17,000,000
Guarantees and Indemnities
Percentage reimbursement obligation for asbestos claims (as a percent)									50.00%
Term of asbestos supplemental agreement (in years)									5 years
Term of asbestos supplemental agreement, automatic renewal period (in years)									1 year
Number of cases not settled and dismissed creating potential liability (in cases)										230
Liability under indemnities					20,000,000					53,000,000
Maximum liability under indemnity per Mountainview purchase agreement for damages and other amounts	60,000,000
Senior rent payment						47,000,000	48,000,000
Equity rent payment							65,000,000
Rent Reserve Letter Of Credit Outstanding Amount								$ 48,000,000

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Summary of Significant Accounting Policies (Earnings Per Share) (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Basic earnings per share - continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$ 266	$ 411	$ 486	$ 805
Participating securities dividends	0	0	0	0
Income from continuing operations available to common shareholders	266	411	486	805
Weighted average common shares outstanding (in shares)	326,000,000	326,000,000	326,000,000	326,000,000
Basic earnings per share - continuing operations (in dollars per share)	$ 0.81	$ 1.26	$ 1.49	$ 2.47
Diluted earnings per share - continuing operations:
Income from continuing operations available to common shareholders	266	411	486	805
Income impact of assumed conversions	0	2	1	3
Income from continuing operations available to common shareholders and assumed conversions	$ 266	$ 413	$ 487	$ 808
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	3,000,000	2,000,000	3,000,000
Adjusted weighted average shares - diluted (in shares)	329,000,000	329,000,000	328,000,000	329,000,000
Diluted earnings per share - continuing operations (in dollars per share)	$ 0.81	$ 1.25	$ 1.48	$ 2.46
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)	3,238,581	5,943,378	4,819,683	8,970,290

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Consolidated Statements of Changes in Equity (Tables)

9 Months Ended

Sep. 30, 2012

Stockholders' Equity Note [Abstract]

Consoldiated Statements of Changes in Equity

The following table provides the changes in equity for the nine months ended September 30, 2012.

	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, 2011	$	2,360		$	(139	)	$	7,834		$	10,055		$	2		$	1,029		$	11,086
Net income	—			—			357			357			12			66			435
Other comprehensive loss	—			(29		)	—			(29		)	—			—			(29		)
Contributions from noncontrolling interests1	—			—			—			—			238			—			238
Transfer of assets to Capistrano Wind Partners2	(21		)	—			—			(21		)	—			—			(21		)
Common stock dividends declared ($0.975 per share)	—			—			(318		)	(318		)	—			—			(318		)
Dividends, distributions to noncontrolling interests and other	—			—			—			—			(14		)	(66		)	(80		)
Stock-based compensation and other	19			—			(64		)	(45		)	—			—			(45		)
Noncash stock-based compensation and other	27			—			(2		)	25			—			—			25
Issuance of preference stock	—			—			—			—			—			804			804
Redemption of preference stock	—			—			(1		)	(1		)	—			(74		)	(75		)
Balance at September 30, 2012	$	2,385		$	(168	)	$	7,806		$	10,023		$	238		$	1,759		$	12,020

¹  Funds contributed by third-party investors related to the Capistrano Wind equity capital raise are reported in noncontrolling interest. For further information, see Note 3.

²  Common stock was reduced by $21 million during the nine months ended September 30, 2012 due to a new tax basis in the assets transferred to Capistrano Wind Partners. For further information, see Note 3.

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 interest1	(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.

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Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2012

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, 2012		December 31, 2011
Current assets	$	71	$	36
Net property, plant and equipment	1,090		675
Other long-term assets	73		5
Total assets	$	1,234	$	716
Current liabilities	$	40	$	28
Long-term debt net of current portion	172		57
Deferred revenues	172		69
Long-term derivative liabilities	23		—
Other long-term liabilities	38		22
Total liabilities	$	445	$	176
Noncontrolling interests	$	238	$	2

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2012

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 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 2011 Form 10-K. The same accounting policies are followed for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2012, discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2011 Form 10-K.

In the opinion of management, all adjustments, consisting of recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and nine-month periods ended September 30, 2012 are not necessarily indicative of the operating results for the full year.

The December 31, 2011 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Interim Financial Statements

On September 21, 2012, EME Homer City Generation L.P. ("Homer City") and Homer City Generation L.P., an affiliate of General Electric Capital Corporation ("GECC"), entered into a Master Transaction Agreement ("Homer City MTA") for the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities.

Beginning in the third quarter of 2012, Homer City met the definition of a discontinued operation and was classified separately in Edison International's consolidated financial statements. Previously issued financial statements have been restated to reflect discontinued operations reported subsequent to the original issuance date. For further information, see Note 18—Discontinued Operations. Except as indicated, amounts in the notes to the consolidated financial statements relate to continuing operations of Edison International.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $933 million and $1.3 billion at September 30, 2012 and December 31, 2011, respectively. Generally, the carrying value of cash equivalents equals the fair value, as these investments have original 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 $234 million and $220 million of checks issued, but not yet paid by the financial institution, from cash to accounts payable at September 30, 2012 and December 31, 2011, respectively.

Restricted Cash and Cash Equivalents, and Restricted Deposits

Restricted cash and cash equivalents at September 30, 2012 and December 31, 2011 included $97 million received from a wind project financing that was held in escrow at those dates. At September 30, 2012, restricted deposits included $48 million to support outstanding letters of credit issued under EME's letter of credit facilities.

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, 2012		December 31, 2011
Coal, gas, fuel oil and other raw materials	$	138	$	143
Spare parts, materials and supplies	370		376
Total inventory	$	508	$	519

Revenue Recognition

Electric Utility Revenue

Operating revenue is recognized when electricity is delivered and includes amounts for services rendered but unbilled at the end of each reporting period. During the first nine months of 2012, pending the outcome of the 2012 GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement included in customer rates. A GRC memorandum account has been established for SCE, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.

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)	2012		2011		2012		2011
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	266	$	411	$	486	$	805
Participating securities dividends	—		—		—		—
Income from continuing operations available to common shareholders	$	266	$	411	$	486	$	805
Weighted average common shares outstanding	326		326		326		326
Basic earnings per share – continuing operations	$	0.81	$	1.26	$	1.49	$	2.47
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	266	$	411	$	486	$	805
Income impact of assumed conversions	—		2		1		3
Income from continuing operations available to common shareholders and assumed conversions	$	266	$	413	$	487	$	808
Weighted average common shares outstanding	326		326		326		326
Incremental shares from assumed conversions	3		3		2		3
Adjusted weighted average shares – diluted	329		329		328		329
Diluted earnings per share – continuing operations	$	0.81	$	1.25	$	1.48	$	2.46

Stock-based compensation awards to purchase 3,238,581 and 5,943,378 shares of common stock for the three months ended September 30, 2012 and 2011, respectively, and 4,819,683 and 8,970,290 shares of common stock for the nine months ended September 30, 2012 and 2011, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares and therefore, the effect would have been antidilutive.

New Accounting Guidance

Accounting Guidance Adopted in 2012

Fair Value Measurement

In May 2011, the Financial Accounting Standards Board ("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 adopted this guidance effective January 1, 2012. For further information, see Note 4.

Presentation of Comprehensive Income

In June 2011 and December 2011, the FASB issued accounting standards updates 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 adopted this guidance January 1, 2012, and elected to present two separate but consecutive statements. The adoption of these accounting standards updates did not change the items that constitute net income and other comprehensive income.

Accounting Guidance Not Yet Adopted

Offsetting Assets and Liabilities

In December 2011, the FASB issued an accounting standards update modifying the disclosure requirements about the nature of an entity's rights of offsetting assets and liabilities in the statement of financial position under master netting agreements and related arrangements associated with financial and derivative instruments. The guidance requires increased disclosure of the gross and net recognized assets and liabilities, collateral positions and narrative descriptions of setoff rights. Edison International will adopt this guidance effective January 1, 2013.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value by Level

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

	September 30, 2012
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	933	$	—	$	—		$	—		$	933
Derivative contracts:
Electricity	—		85		148			(44		)	189
Natural gas	1		—		—			(1		)	—
Fuel Oil	2		—		—			(2		)	—
Tolling	—		—		4			—			4
Subtotal of derivative contracts	3		85		152			(47		)	193
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks3	2,227		—		—			—			2,227
Municipal bonds	—		654		—			—			654
U.S. government and agency securities	467		122		—			—			589
Corporate bonds4	—		374		—			—			374
Short-term investments, primarily cash equivalents5	—		145		—			—			145
Subtotal of nuclear decommissioning trusts	2,694		1,295		—			—			3,989
Total assets6	3,638		1,380		152			(47		)	5,123
Liabilities at Fair Value
Derivative contracts:
Electricity	—		8		17			(15		)	10
Natural gas	1		115		6			(48		)	74
Tolling	—		—		617			—			617
Subtotal of derivative contracts	1		123		640			(63		)	701
Interest rate contracts	—		125		—			—			125
Total liabilities	1		248		640			(63		)	826
Net assets (liabilities)	$	3,637	$	1,132	$	(488	)	$	16		$	4,297

	December 31, 2011
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	1,293	$	—	$	—		$	—		$	1,293
Derivative contracts:
Electricity	—		65		218			(58		)	225
Natural gas	4		5		—			(7		)	2
Fuel oil	4		—		—			(4		)	—
Tolling	—		—		10			—			10
Subtotal of derivative contracts	8		70		228			(69		)	237
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks3	1,899		—		—			—			1,899
Municipal bonds	—		756		—			—			756
U.S. government and agency securities	433		147		—			—			580
Corporate bonds4	—		317		—			—			317
Short-term investments, primarily cash equivalents5	—		15		—			—			15
Subtotal of nuclear decommissioning trusts	2,332		1,235		—			—			3,567
Total assets6	3,641		1,305		228			(69		)	5,105
Liabilities at Fair Value
Derivative contracts:
Electricity	—		10		77			(17		)	70
Natural gas	—		234		23			(52		)	205
Tolling	—		—		451			—			451
Subtotal of derivative contracts	—		244		551			(69		)	726
Interest rate contracts	—		90		—			—			90
Total liabilities	—		334		551			(69		)	816
Net assets (liabilities)	$	3,641	$	971	$	(323	)	$	—		$	4,289

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 and cash equivalents on Edison International's consolidated balance sheets.

³  Approximately 67% and 70% of the equity investments were located in the United States at September 30, 2012 and December 31, 2011, respectively.

⁴  At September 30, 2012 and December 31, 2011, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $42 million and $22 million, respectively.

⁵  Excludes net receivables of $8 million and $25 million at September 30, 2012 and December 31, 2011, respectively, of interest and dividend receivables as well as receivables and payables related to pending securities sales and purchases.

⁶  Excludes other investments of $70 million and $81 million at September 30, 2012 and December 31, 2011, respectively, primarily related to the cash surrender value of company owned life insurance investments which are used to fund certain executive benefits including deferred compensation. Also excludes other investments of $77 million and $118 million at September 30, 2012 and December 31, 2011, respectively, primarily related to leveraged leases

Summary of Changes in Fair Value of Level 3 Assets and Liabilities

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

	Three months ended September 30,								Nine months ended September 30,
(in millions)	2012				2011				2012				2011
Fair value of net assets (liabilities) at beginning of period	$	(343	)		$	(275	)		$	(323	)		$	97
Total realized/unrealized gains (losses):
Included in earnings1	12				(4		)		20				14
Included in regulatory assets and liabilities2	(124		)	3	162			3	(140		)	3	(220		)	3
Included in accumulated other comprehensive income4	(1		)		1				1				(2		)
Purchases	41				24				111				51
Settlements	(73		)		(8		)		(106		)		(38		)
Transfers into Level 3	—				—				—				—
Transfers out of Level 35	—				—				(51		)		(2		)
Fair value of net liabilities at end of period	$	(488	)		$	(100	)		$	(488	)		$	(100	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period6	$	(173	)		$	(110	)		$	(181	)		$	(425	)

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  Included in reclassification adjustments in Edison International's consolidated statements of other comprehensive income.

⁵  Transfers out of Level 3 into Level 2 occurred due to significant observable inputs becoming available as the transactions near maturity.

⁶  Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income was a loss of $7 million for three months ended September 30, 2012, and a gain of $7 million for the nine months ended September 30, 2011. The remainder of the unrealized losses relate to SCE. See 2 above.

Valuation Techniques and Significant Unobservable Inputs Used to Determine Fair Value for Level 3 Assets and Liabilities

The following table sets forth the valuation techniques and significant unobservable inputs used to determine fair value for Level 3 assets and liabilities at September 30, 2012:

	Fair Value (in millions)							Significant	Range
	Assets			Liabilities			Valuation Technique(s)	Unobservable Input	(Weighted Average)
Electricity:
Options	$	23		$	26		Option model	Volatility of gas prices	23% - 41% (31%)
								Volatility of power prices	28% - 60% (39%)
								Power prices	$38.10 - $58.80 ($45.30)
Forwards	15			20			Discounted cash flow	Power prices	$18.25 - $64.50 ($34.57)
Congestion contracts	100			—			Market simulation model	Load forecast	7,597 MW - 26,612 MW
								Power prices	$(13.90) - $226.75
								Gas prices	$2.95 - $7.78
Congestion contracts	62			24			Latest auction pricing	Congestion prices	$(5.39) - $11.87 ($0.13)
Gas options	—			6			Option model	Volatility of gas prices	24% - 41% (35%)
Tolling	5			617			Option model	Volatility of gas prices	17% - 41% (21%)
								Volatility of power prices	26% - 60% (28%)
								Power prices	$33.20 - $100.80 ($56.10)
Netting	(53		)	(53		)
Total derivative contracts	$	152		$	640

Carrying Amounts and Fair Values of Long-term Debt, Including Current Portion

The carrying value and fair value of long-term debt are:

	September 30, 2012				December 31, 2011
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current portion	$	14,273	$	14,452	$	13,746	$	14,264

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Other Income and Expenses (Tables)

9 Months Ended

Sep. 30, 2012

Other Income and Expenses [Abstract]

Other Income and Expenses

Other income and expenses are as follows:

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2012		2011		2012		2011
Other income:
Equity allowance for funds used during construction	$	23	$	18	$	71	$	74
Increase in cash surrender value of life insurance policies	6		6		20		19
Other	7		2		12		10
Total utility other income	36		26		103		103
Competitive power generation and other income	1		1		2		7
Total other income	$	37	$	27	$	105	$	110
Other expenses:
Civic, political and related activities and donations	$	5	$	6	$	22	$	21
Other	4		4		14		14
Total utility other expenses	9		10		36		35
Competitive power generation and other expenses	1		1		—		2
Total other expenses	$	10	$	11	$	36	$	37

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Derivative Instruments and Hedging Activities (Additional Disclosures) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011		Dec. 31, 2011
Collateral provided to counterparties:
Offset against derivative liabilities	$ 54				$ 54				$ 53
Reflected in margin and collateral deposits	88				88				58
Collateral received from counterparties:
Offset against derivative assets	39				39				53
Commodity Contracts
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Unrealized derivative gains (losses) after taxes recorded in accumulated other comprehensive income	7		10		7		10
Interest Rate Contracts
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Unrealized derivative gains (losses) after taxes recorded in accumulated other comprehensive income	(79)		(49)		(79)		(49)
Cash flow hedges | Commodity Contracts
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Beginning of period derivative gains (losses)					35	[1]	43	[1]
Effective portion of changes in fair value					3	[1]	2	[1]
End of period derivative gains (losses)	7	[1]	16	[1]	7	[1]	16	[1]
Cash flow hedges | Interest Rate Contracts
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Beginning of period derivative gains (losses)					(90)	[1]	(16)	[1]
Effective portion of changes in fair value					(35)	[1]	(64)	[1]
End of period derivative gains (losses)	(125)	[1]	(80)	[1]	(125)	[1]	(80)	[1]
Cash flow hedges | Competitive power generation revenues | Commodity Contracts
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Reclassification to earnings					(31)	[1]	(29)	[1]
Cash flow hedges | Competitive power generation revenues | Interest Rate Contracts
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Reclassification to earnings					0	[1]	0	[1]
Cash flow hedges | Operating revenues
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Amount of gains (losses) for cash flow hedge ineffectiveness	(2)		2
Economic hedges | Competitive power generation revenues
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Gain (loss) on derivative instruments	8		(3)		25		5
Economic hedges | Fuel
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Gain (loss) on derivative instruments	3		(3)		2		1
Trading activities | Competitive power generation revenues
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Gain (loss) on derivative instruments	22		11		72		68
Edison Mission Energy | Cash flow hedges | Competitive power generation revenues
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Amount of gains (losses) for cash flow hedge ineffectiveness					0		2
Electric Utility | Southern California Edison | Economic hedges
Derivatives
Realized losses	(77)		(58)		(199)		(132)
Unrealized losses	(91)		(110)		(29)		(433)
Collateral already posted, fair value	0				0				0
Additional collateral, aggregate fair value	25				25
Accumulated Other Comprehensive Income (Loss) Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges
Aggregate fair value of all derivative liabilities with credit-risk-related contingent features	$ 113				$ 113				$ 216

[1] Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive loss at September 30, 2012 and 2011 for commodity and interest rate contracts were $7 million and $(79) million, and $10 million and $(49) million, respectively.

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Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Electric utility	$ 3,730	$ 3,385	$ 8,791	$ 8,060
Competitive power generation	340	437	1,009	1,277
Total operating revenue	4,070	3,822	9,800	9,337
Fuel	270	272	678	671
Purchased power	1,612	1,264	3,049	2,422
Operation and maintenance	1,152	1,071	3,450	3,325
Depreciation, decommissioning and amortization	465	430	1,389	1,272
(Gain) loss on sale of assets and other	(65)	0	(60)	8
Total operating expenses	3,434	3,037	8,506	7,698
Operating income	636	785	1,294	1,639
Interest and dividend income	3	4	19	38
Equity in income from unconsolidated affiliates, net	25	56	42	68
Other income	37	27	105	110
Interest expense	(214)	(203)	(643)	(600)
Other expenses	(10)	(11)	(36)	(37)
Income from continuing operations before income taxes	477	658	781	1,218
Income tax expense	181	232	217	370
Income from continuing operations	296	426	564	848
Income (loss) from discontinued operations, net of tax	(76)	15	(129)	(3)
Net income	220	441	435	845
Dividends on preferred and preference stock of utility	25	15	66	44
Other noncontrolling interests	5	0	12	(1)
Net income attributable to Edison International common shareholders	190	426	357	802
Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	266	411	486	805
Income (loss) from discontinued operations, net of tax	(76)	15	(129)	(3)
Net income attributable to Edison International common shareholders	$ 190	$ 426	$ 357	$ 802
Basic earnings (loss) per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding (in shares)	326	326	326	326
Continuing operations (in dollars per share)	$ 0.81	$ 1.26	$ 1.49	$ 2.47
Discontinued operations (in dollars per share)	$ (0.23)	$ 0.05	$ (0.40)	$ (0.01)
Total (in dollars per share)	$ 0.58	$ 1.31	$ 1.09	$ 2.46
Diluted earnings (loss) per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities (in shares)	329	329	328	329
Continuing operations (in dollars per share)	$ 0.81	$ 1.25	$ 1.48	$ 2.46
Discontinued operations (in dollars per share)	$ (0.23)	$ 0.05	$ (0.39)	$ (0.01)
Total (in dollars per share)	$ 0.58	$ 1.30	$ 1.09	$ 2.45
Dividends declared per common share (in dollars per share)	$ 0.325	$ 0.320	$ 0.975	$ 0.960

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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, 2012	Sep. 30, 2011	Sep. 30, 2012		Sep. 30, 2011
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, at the beginning of the period			$ 11,086		$ 11,494
Net income (loss)	220	441	435		845
Other comprehensive loss	(11)	(27)	(29)		(48)
Contributions from noncontrolling interests			238	[1]
Transfer of assets to Capistrano Wind Partners			(21)	[2]
Common stock dividends declared ($0.975 and $0.96 per share, 2012 and 2011 respectively)			(318)		(313)
Dividends, distributions to noncontrolling interests and other			(80)		(45)
Stock-based compensation and other			(45)		(14)
Noncash stock-based compensation and other			25		18
Purchase of noncontrolling interest					(14)	[3]
Issuance of preference stock			804		123
Redemption of preference stock			(75)
Balance, at the end of the period	12,020	12,046	12,020		12,046
Dividends declared per common share (in dollars per share)	$ 0.325	$ 0.320	$ 0.975		$ 0.960
EMG | Pinnacle Wind Force, LLC, and Broken Bow I, LLC and all assets of the Crofton Bluffs project
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Ownership interest (as a percentage)					100.00%
Common Stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, at the beginning of the period			2,360		2,331
Net income (loss)			0		0
Other comprehensive loss			0		0
Contributions from noncontrolling interests			0	[1]
Transfer of assets to Capistrano Wind Partners			(21)	[2]
Common stock dividends declared ($0.975 and $0.96 per share, 2012 and 2011 respectively)			0		0
Dividends, distributions to noncontrolling interests and other			0		0
Stock-based compensation and other			19		7
Noncash stock-based compensation and other			27		22
Purchase of noncontrolling interest					(14)	[3]
Issuance of preference stock			0		0
Redemption of preference stock			0
Balance, at the end of the period	2,385	2,346	2,385		2,346
Accumulated Other Comprehensive Loss
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, at the beginning of the period			(139)		(76)
Net income (loss)			0		0
Other comprehensive loss			(29)		(48)
Contributions from noncontrolling interests			0	[1]
Transfer of assets to Capistrano Wind Partners			0	[2]
Common stock dividends declared ($0.975 and $0.96 per share, 2012 and 2011 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 interest					0	[3]
Issuance of preference stock			0		0
Redemption of preference stock			0
Balance, at the end of the period	(168)	(124)	(168)		(124)
Retained Earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, at the beginning of the period			7,834		8,328
Net income (loss)			357		802
Other comprehensive loss			0		0
Contributions from noncontrolling interests			0	[1]
Transfer of assets to Capistrano Wind Partners			0	[2]
Common stock dividends declared ($0.975 and $0.96 per share, 2012 and 2011 respectively)			(318)		(313)
Dividends, distributions to noncontrolling interests and other			0		0
Stock-based compensation and other			(64)		(21)
Noncash stock-based compensation and other			(2)		(3)
Purchase of noncontrolling interest					0	[3]
Issuance of preference stock			0		0
Redemption of preference stock			(1)
Balance, at the end of the period	7,806	8,793	7,806		8,793
Subtotal
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, at the beginning of the period			10,055		10,583
Net income (loss)			357		802
Other comprehensive loss			(29)		(48)
Contributions from noncontrolling interests			0	[1]
Transfer of assets to Capistrano Wind Partners			(21)	[2]
Common stock dividends declared ($0.975 and $0.96 per share, 2012 and 2011 respectively)			(318)		(313)
Dividends, distributions to noncontrolling interests and other			0		0
Stock-based compensation and other			(45)		(14)
Noncash stock-based compensation and other			25		19
Purchase of noncontrolling interest					(14)	[3]
Issuance of preference stock			0		0
Redemption of preference stock			(1)
Balance, at the end of the period	10,023	11,015	10,023		11,015
Other
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, at the beginning of the period			2		4
Net income (loss)			12		(1)
Other comprehensive loss			0		0
Contributions from noncontrolling interests			238	[1]
Transfer of assets to Capistrano Wind Partners			0	[2]
Common stock dividends declared ($0.975 and $0.96 per share, 2012 and 2011 respectively)			0		0
Dividends, distributions to noncontrolling interests and other			(14)		(1)
Stock-based compensation and other			0		0
Noncash stock-based compensation and other			0		0
Purchase of noncontrolling interest					0	[3]
Issuance of preference stock			0		0
Redemption of preference stock			0
Balance, at the end of the period	238	2	238		2
Preferred Stock and Preference Stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, at the beginning of the period			1,029		907
Net income (loss)			66		44
Other comprehensive loss			0		0
Contributions from noncontrolling interests			0	[1]
Transfer of assets to Capistrano Wind Partners			0	[2]
Common stock dividends declared ($0.975 and $0.96 per share, 2012 and 2011 respectively)			0		0
Dividends, distributions to noncontrolling interests and other			(66)		(44)
Stock-based compensation and other			0		0
Noncash stock-based compensation and other			0		(1)
Purchase of noncontrolling interest					0	[3]
Issuance of preference stock			804		123
Redemption of preference stock			(74)
Balance, at the end of the period	$ 1,759	$ 1,029	$ 1,759		$ 1,029

[1] Funds contributed by third-party investors related to the Capistrano Wind equity capital raise are reported in noncontrolling interest. For further information, see Note 3.

[2] Common stock was reduced by $21 million during the nine months ended September 30, 2012 due to a new tax basis in the assets transferred to Capistrano Wind Partners. For further information, see Note 3.

[3] 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.

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Receivables, allowances for uncollectible accounts (in dollars)	$ 75	$ 75
Utility property, plant and equipment, accumulated depreciation (in dollars)	7,378	6,894
Competitive power generation and other property, plant and equipment, accumulated depreciation (in dollars)	$ 1,616	$ 1,408
Common stock, no par value (in dollars per share)	$ 0	$ 0
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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Supplemental Cash Flows Information (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash payments (receipts) for interest and taxes:
Interest - net of amounts capitalized	$ 550	$ 529
Tax refunds - net	(71)	(330)
Details of debt exchange:
Pollution-control bonds redeemed	0	(86)
Pollution-control bonds issued	0	86
Dividends declared but not paid:
Common stock	106	104
Preferred and preference stock	6	12
Accrued capital expenditures	$ 431	$ 393

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Compensation and Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2012

Pension Plans

Pension and Other Postretirement Benefits

Expense Components for Plans

Expense components are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Service cost	$	49		$	43		$	135		$	129
Interest cost	49			52			147			156
Expected return on plan assets	(56		)	(60		)	(174		)	(180		)
Amortization of prior service cost	1			2			3			6
Amortization of net loss	21			6			57			18
Expense under accounting standards	64			43			168			129
Regulatory adjustment (deferred)	(57		)	(6		)	(3		)	(18		)
Total expense recognized	$	7		$	37		$	165		$	111

Postretirement Benefits Other Than Pensions

Pension and Other Postretirement Benefits

Expense Components for Plans

Expense components are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Service cost	$	13		$	11		$	39		$	33
Interest cost	30			33			90			99
Expected return on plan assets	(27		)	(28		)	(81		)	(84		)
Special termination benefits1	3			—			3			—
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss	12			9			36			27
Total expense	$	22		$	16		$	60		$	48

¹  Due to the reduction in the workforce at San Onofre, Edison International has incurred costs for enhanced retiree health care coverage. See below for further information.

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Planned Sale of Interest in Four Corners (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012
Discontinued Operations and Disposal Groups [Abstract]
Sales price	$ 294
Sales price, after adjustment	$ 279

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Other Investments

9 Months Ended

Sep. 30, 2012

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 through 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, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Stocks	—	$	957	$	865	$	2,227	$	1,899
Municipal bonds	2054	520		625		654		756
U.S. government and agency securities	2042	526		516		589		580
Corporate bonds	2054	287		259		374		317
Short-term investments and receivables/payables	One-year	147		38		153		40
Total		$	2,437	$	2,303	$	3,997	$	3,592

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Proceeds from sales of securities (which are reinvested) were $428 million and $962 million for the three months ended September 30, 2012 and 2011, respectively, and $1.5 billion and $2.1 billion for the nine months ended September 30, 2012 and 2011, respectively. Unrealized holding gains, net of losses, were $1.6 billion and $1.3 billion at September 30, 2012 and December 31, 2011, 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)	2012			2011			2012			2011
Balance at beginning of period	$	3,810		$	3,657		$	3,592		$	3,480
Gross realized gains	13			46			54			81
Gross realized losses	—			(5		)	(5		)	(5		)
Unrealized gains (losses) – net	156			(305		)	272			(199		)
Other-than-temporary impairments	(7		)	(22		)	(30		)	(35		)
Interest, dividends, contributions and other	25			22			114			71
Balance at end of period	$	3,997		$	3,393		$	3,997		$	3,393

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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Accumulated Other Comprehensive Loss (Tables)

9 Months Ended

Sep. 30, 2012

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

Components of Accumulated Other Comprehensive Loss

Edison International's accumulated other comprehensive loss consists of:

(in millions)	Unrealized 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, 2011	$	(34	)	$	(100	)	$	(5	)	$	(139	)
Change for 2012	(38		)	9			—			(29		)
Balance at September 30, 2012	$	(72	)	$	(91	)	$	(5	)	$	(168	)

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Planned Sale of Interest in Four Corners

9 Months Ended

Sep. 30, 2012

Discontinued Operations and Disposal Groups [Abstract]

Planned Sale of Interest in Four Corners

Planned Sale of Interest in Four Corners

In November 2010, SCE entered into an agreement to sell its ownership interest in Units 4 and 5 of the Four Corners Generating Station, a coal-fired electric generating facility in New Mexico, to the operator of the facility, Arizona Public Service Company. During 2012, the CPUC and the Arizona Corporation Commission ("ACC") approved the transaction. As part of its sale approval, the ACC stipulated that the sale cannot close earlier than December 1, 2012 which under the adjustment mechanism set forth in the sales agreement would reduce the sale price from $294 million to $279 million. The price is also subject to further adjustments. The closing of the sale is contingent upon the receipt of other specified closing conditions, including APS obtaining a long-term fuel supply agreement for the plant. The sale agreement provides for either party to terminate if it is not completed by December 31, 2012. Any gain on the sale will be for the benefit of SCE's customers and, therefore, will not affect SCE's earnings.

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Business Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011		Dec. 31, 2011
Segment Reporting Information
Operating Revenue:	$ 4,070		$ 3,822		$ 9,800		$ 9,337
Net Income (Loss) attributable to Edison International:	190		426		357		802
Total Assets:	50,545				50,545				48,039
Income (loss) from discontinued operations, net of tax	(76)		15		(129)		(3)
Electric Utility
Segment Reporting Information
Operating Revenue:	3,731		3,386		8,794		8,063
Net Income (Loss) attributable to Edison International:	363		406		736		838
Total Assets:	43,059				43,059				40,315
Competitive Power Generation
Segment Reporting Information
Operating Revenue:	340		437		1,009		1,277
Net Income (Loss) attributable to Edison International:	(137)	[1]	33	[1]	(331)	[1]	(17)	[1]
Total Assets:	7,934				7,934				8,392
Parent and Other
Segment Reporting Information
Operating Revenue:	(1)	[2]	(1)	[2]	(3)	[2]	(3)	[2]
Net Income (Loss) attributable to Edison International:	(36)	[2]	(13)	[2]	(48)	[2]	(19)	[2]
Total Assets:	$ (448)	[2]			$ (448)	[2]			$ (668)	[2]

[1] Includes earnings (losses) from discontinued operations of $(76) million and $15 million for the three months ended September 30, 2012 and 2011, respectively, and $(129) million and $(3) million for the nine months ended September 30, 2012 and 2011, 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, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash flows from operating activities:
Net income	$ 435	$ 845
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	1,389	1,272
Regulatory impacts of net nuclear decommissioning trust earnings	147	131
Other amortization	73	112
Gain on sale of assets and other	(60)	6
Stock-based compensation	28	22
Equity in income from unconsolidated affiliates	(42)	(68)
Distributions from unconsolidated affiliates	15	52
Deferred income taxes and investment tax credits	(20)	373
Income from leveraged leases	(4)	(4)
Proceeds from U.S. treasury grants	73	310
Changes in operating assets and liabilities:
Receivables	(293)	(205)
Inventory	11	(25)
Margin and collateral deposits, net of collateral received	(31)	6
Prepaid taxes	52	318
Other current assets	(264)	(321)
Rent payments in excess of levelized rent expense	(95)	(96)
Accounts payable	347	178
Accrued taxes	61	76
Other current liabilities	(87)	(189)
Derivative assets and liabilities, net	(8)	137
Regulatory assets and liabilities, net	210	(73)
Other assets	(30)	(20)
Other liabilities	256	1
Operating cash flows from continuing operations	2,163	2,838
Operating cash flows from discontinued operations, net	(5)	(14)
Net cash provided by operating activities	2,158	2,824
Cash flows from financing activities:
Long-term debt issued	549	686
Long-term debt issuance costs	(12)	(24)
Long-term debt repaid	(36)	(97)
Bonds purchased	0	(86)
Preference stock issued, net	804	123
Preference stock redeemed	(75)	0
Short-term debt financing, net	(10)	573
Settlements of stock-based compensation, net	(45)	(14)
Cash contributions from noncontrolling interests	238	0
Dividends and distributions to noncontrolling interests	(75)	(43)
Dividends paid	(318)	(313)
Net cash provided by financing activities from continuing operations	1,020	805
Cash flows from investing activities:
Capital expenditures	(3,371)	(3,481)
Purchase of interest in acquired companies	0	(3)
Proceeds from sale of nuclear decommissioning trust investments	1,525	2,108
Purchases of nuclear decommissioning trust investments and other	(1,689)	(2,254)
Proceeds from sale of interest in project, net	107	0
Proceeds from partnerships and unconsolidated subsidiaries, net of investment	7	6
Restricted deposits and restricted cash and cash equivalents	(75)	4
Customer advances for construction and other investments	3	(4)
Investing cash flows from continuing operations	(3,493)	(3,624)
Investing cash flows from discontinued operations, net	(19)	(10)
Net cash used by investing activities	(3,512)	(3,634)
Net (decrease) increase in cash and cash equivalents from continuing operations	(310)	19
Cash and cash equivalents at beginning of period from continuing operations	1,390	1,261
Cash and cash equivalents at end of period from contuing operations	1,080	1,280
Net decrease in cash and cash equivalents from discontinued operations	(24)	(24)
Cash and cash equivalents at beginning of period from discontinued operations	79	128
Cash and cash equivalents at end of period from discontinued operations	$ 55	$ 104

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Net income	$ 220	$ 441	$ 435	$ 845
Pension and postretirement benefits other than pensions:
Net loss arising during the period, net of income tax benefit of $3 for the nine months ended September 30, 2012	0	0	(3)	0
Amortization of net loss included in net income, net of income tax expense of $2 and $1 for the three months and $7 and $4 for the nine months ended September 30, 2012 and 2011, respectively	4	3	12	7
Unrealized loss on derivatives qualified as cash flow hedges:
Unrealized holding loss arising during the period, net of income tax benefit of $11 and $19 for the three months and $13 and $24 for the nine months ended September 30, 2012 and 2011, respectively	(16)	(30)	(19)	(38)
Reclassification adjustments included in net income, net of income tax expense (benefit) of $1 and none for the three months and $(12) and $(12) for the nine months ended September 30, 2012 and 2011, respectively	1	0	(19)	(17)
Other comprehensive loss	(11)	(27)	(29)	(48)
Comprehensive income	209	414	406	797
Less: Comprehensive income attributable to noncontrolling interests	30	15	78	43
Comprehensive income attributable to Edison International	$ 179	$ 399	$ 328	$ 754

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Environmental Developments

9 Months Ended

Sep. 30, 2012

Environmental Developments [Abstract]

Environmental Developments

Environmental Developments

Cross-State Air Pollution Rule

In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated the US EPA's Cross-State Air Pollution Rule ("CSAPR") and directed the US EPA to continue administering the Clean Air Interstate Rule pending the promulgation of a valid replacement. In October 2012, the US EPA filed a petition seeking to have the decision reviewed by the full District of Columbia Circuit.

Hazardous Air Pollutant Regulations

In December 2011, the US EPA announced the Mercury and Air Toxics Standards rule, limiting emissions of hazardous air pollutants from coal- and oil-fired electrical generating units. The rule was published in the Federal Register on February 16, 2012, and became effective on April 16, 2012. A number of parties have filed notices of appeal challenging the rule.

Greenhouse Gas Regulation

In March 2012, the US EPA announced proposed carbon dioxide emissions limits for new power plants. The status of the US EPA's efforts to develop greenhouse gas emissions performance standards for existing plants is unknown.

In June 2012, the U.S. Court of Appeals for the D.C. Circuit dismissed the challenge by industry groups and some states to the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, known as the "GHG tailoring rule." In August 2012, states and industry groups challenging the rule filed a petition seeking to have the decision reviewed by the full District of Columbia Circuit.

In July 2012, the US EPA published a final rule maintaining the CO₂ equivalent emissions thresholds (for purposes of PSD and Title V permitting) originally established in the GHG tailoring rule.

Greenhouse Gas Litigation

In March 2012, the federal district court in Mississippi dismissed, in its entirety, the purported class action complaint filed by private citizens in May 2011, naming a large number of defendants, including SCE, EME and other Edison International subsidiaries, for damages allegedly arising from Hurricane Katrina. In April 2012, the plaintiffs filed an appeal with the Fifth Circuit Court of Appeals. 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.

In September 2012, a three-judge panel of the U.S Court of Appeals for the Ninth Circuit affirmed the dismissal of a case brought against Edison International and other defendants, by the Alaskan Native Village of Kivalina. In October 2012, the plaintiffs requested a rehearing by a larger panel of Ninth Circuit judges.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2012	Oct. 30, 2012
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, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		325,811,206

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Accumulated Other Comprehensive Loss

9 Months Ended

Sep. 30, 2012

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 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, 2011	$	(34	)	$	(100	)	$	(5	)	$	(139	)
Change for 2012	(38		)	9			—			(29		)
Balance at September 30, 2012	$	(72	)	$	(91	)	$	(5	)	$	(168	)

Included in accumulated other comprehensive loss at September 30, 2012 was $7 million, net of tax, of unrealized gains on commodity-based cash flow hedges, and $79 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 through December 31, 2013.

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 $3 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenues recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Net loss arising during the period, income tax expense (benefit)			$ (3)
Amortization of net loss included in net income, income tax expense (benefit)	2	1	7	4
Unrealized holding gain (loss) arising during the period, income tax expense (benefit)	(11)	(19)	(13)	(24)
Reclassification adjustments included in net income, income tax expense (benefit)	$ 1	$ 0	$ (12)	$ (12)

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Debt and Credit Agreements

9 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

Debt and Credit Agreements

Debt and Credit Agreements

Project Financings

Broken Bow and Crofton Bluffs

Effective March 30, 2012, EME, through its subsidiaries, Broken Bow Wind, LLC and Crofton Bluffs Wind, LLC, completed two nonrecourse financings of its interests in the Broken Bow and Crofton Bluffs wind projects. The financings included construction loans totaling $79 million that are required to be converted to 15-year amortizing term loans by March 31, 2013, subject to meeting specified conditions, $13 million letter of credit facilities and $6 million working capital facilities. Interest under the construction and term loans will accrue at London Interbank Offered Rate (LIBOR) plus 2.875%, with the term loan rate increasing 0.125% after the third, sixth, ninth, and twelfth years. As of September 30, 2012, $21 million and $6 million were outstanding under the construction loans included in short-term debt on EME's consolidated balance sheet, and letters of credit facilities, respectively.

Tapestry Wind

In December 2011, EME through its subsidiary, Tapestry Wind, LLC, completed a nonrecourse financing of its interests in the Taloga, Buffalo Bear and Pinnacle wind projects. A total of $97 million of cash proceeds received from the $214 million10-year partially amortizing term loan was deposited into an escrow account as of December 31, 2011. On February 22, 2012, a neighbor of the Pinnacle project, filed a formal complaint with the West Virginia Public Service Commission regarding, among other things, noise emissions and shadow flicker and requested that the Commission order the project to shut down at night due to alleged noise emissions. This complaint was dismissed on June 1, 2012. On June 27, 2012 and on July 3, 2012, nearly identical complaints were filed with the West Virginia Public Service Commission by two other neighbors and were subsequently dismissed. In addition, on June 25, 2012, each of the three neighbors filed separate civil complaints in the Circuit Court of Mineral County, West Virginia against Pinnacle Wind, LLC, EME, Edison Mission Operations and Maintenance, Inc., and other non-affiliated defendants. The civil complaints allege, among other things, that the noise emissions and shadow flicker from the Pinnacle wind farm constitute a nuisance and seek compensatory damages, punitive damages and other equitable relief. The complaints have been dismissed without prejudice. The release of the loan proceeds in escrow is subject to final resolution of the complaints or further due diligence from the lenders.

Big Sky Turbine Financing

In October 2009, EME, through its subsidiary, Big Sky Wind, LLC (Big Sky), entered into turbine financing arrangements with the turbine manufacturer, totaling approximately $206 million for wind turbine purchase obligations related to the 240 MW Big Sky wind project. The loan has a five-year final maturity, however, specific events, including project performance, may trigger earlier repayment which could occur as early as February 2013. Big Sky is currently involved in a dispute with the lender/turbine manufacturer around whether certain latent defects existing in the turbine equipment would preclude the early repayment provisions. The loan is secured by a leasehold mortgage on the project's real property assets, a pledge of all other collateral of the Big Sky wind project, as well as a cash reserve account into which one-third of distributable cash flow, if any, of the Big Sky wind project is to be deposited on a monthly basis. The loan is also secured by pledges of Big Sky's direct and indirect ownership interests in the project but is non-recourse to EME.

Big Sky will need to arrange alternative financing, if available, to repay the loan at maturity or reach agreement with the lender to extend the maturity date of the loan as EME does not plan to make an investment in the project and is under no obligation to do so. If these efforts are unsuccessful, the lender may foreclose on the project resulting in a write off of the entire investment in the project. At September 30, 2012, EME's net investment in the Big Sky wind project was $130 million.

Long-Term Debt

In March 2012, SCE issued $400 million of 4.05% first and refunding mortgage bonds due in 2042. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.

Credit Agreements and Short-Term Debt

During the second quarter of 2012, SCE replaced its credit facilities with a $2.75 billion five-year revolving credit facility that matures in May 2017. The credit facility is generally used to support commercial paper and letters of credit issued for procurement-related collateral requirements, balancing account undercollections and for general corporate purposes, including working capital requirements to support operations and capital expenditures. At September 30, 2012, SCE's outstanding commercial paper supported by the credit facility was $380 million at a weighted-average interest rate of 0.43%. At September 30, 2012, letters of credit issued under SCE's credit facility aggregated $196 million and are scheduled to expire in twelve months or less. At December 31, 2011, the outstanding commercial paper was $419 million at a weighted-average interest rate of 0.44%.

In February 2012, EME terminated its $564 million revolving credit facility. Midwest Generation's $500 million credit facility expired in June 2012 as per its terms. In the first quarter of 2012, EME completed a $100 million letter of credit facility for EME's general corporate needs and for its projects, which expires on June 30, 2014. Letters of credit issued under this facility are secured by cash collateral at least equal to the issued amount.

During the second quarter of 2012, Edison International (parent) replaced its credit facility with a $1.25 billion five-year revolving credit facility that matures in May 2017. Borrowings under this credit facility are used for general corporate purposes. At September 30, 2012, Edison International (parent) outstanding short-term debt supported by this credit facility was $28 million at a weighted-average interest rate of 1.52%. At December 31, 2011, the outstanding short-term debt was $10 million at a weighted-average interest rate of 0.66%.

Letters of Credit

At September 30, 2012, letters of credit under EME's and its subsidiaries' credit facilities aggregated $154 million. EME had $51 million of cash collateral supporting its letters of credit which were scheduled to expire as follows: $48 million in 2013 and $3 million in 2014. In addition, EME's subsidiaries' credit facilities aggregated $103 million and were scheduled to expire as follows: $2 million in 2012, $49 million in 2013, $21 million in 2017, $18 million in 2018 and $13 million in 2021. Standby letters of credit include $30 million issued in connection with the power purchase agreement with SCE under the Walnut Creek credit facility. Certain letters of credit are subject to automatic annual renewal provisions.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2012

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 considers assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk which was not material as of September 30, 2012 and December 31, 2011.

Assets and liabilities are categorized into a three-level 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:

	September 30, 2012
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	933	$	—	$	—		$	—		$	933
Derivative contracts:
Electricity	—		85		148			(44		)	189
Natural gas	1		—		—			(1		)	—
Fuel Oil	2		—		—			(2		)	—
Tolling	—		—		4			—			4
Subtotal of derivative contracts	3		85		152			(47		)	193
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks3	2,227		—		—			—			2,227
Municipal bonds	—		654		—			—			654
U.S. government and agency securities	467		122		—			—			589
Corporate bonds4	—		374		—			—			374
Short-term investments, primarily cash equivalents5	—		145		—			—			145
Subtotal of nuclear decommissioning trusts	2,694		1,295		—			—			3,989
Total assets6	3,638		1,380		152			(47		)	5,123
Liabilities at Fair Value
Derivative contracts:
Electricity	—		8		17			(15		)	10
Natural gas	1		115		6			(48		)	74
Tolling	—		—		617			—			617
Subtotal of derivative contracts	1		123		640			(63		)	701
Interest rate contracts	—		125		—			—			125
Total liabilities	1		248		640			(63		)	826
Net assets (liabilities)	$	3,637	$	1,132	$	(488	)	$	16		$	4,297

	December 31, 2011
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	1,293	$	—	$	—		$	—		$	1,293
Derivative contracts:
Electricity	—		65		218			(58		)	225
Natural gas	4		5		—			(7		)	2
Fuel oil	4		—		—			(4		)	—
Tolling	—		—		10			—			10
Subtotal of derivative contracts	8		70		228			(69		)	237
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks3	1,899		—		—			—			1,899
Municipal bonds	—		756		—			—			756
U.S. government and agency securities	433		147		—			—			580
Corporate bonds4	—		317		—			—			317
Short-term investments, primarily cash equivalents5	—		15		—			—			15
Subtotal of nuclear decommissioning trusts	2,332		1,235		—			—			3,567
Total assets6	3,641		1,305		228			(69		)	5,105
Liabilities at Fair Value
Derivative contracts:
Electricity	—		10		77			(17		)	70
Natural gas	—		234		23			(52		)	205
Tolling	—		—		451			—			451
Subtotal of derivative contracts	—		244		551			(69		)	726
Interest rate contracts	—		90		—			—			90
Total liabilities	—		334		551			(69		)	816
Net assets (liabilities)	$	3,641	$	971	$	(323	)	$	—		$	4,289

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 and cash equivalents on Edison International's consolidated balance sheets.

³  Approximately 67% and 70% of the equity investments were located in the United States at September 30, 2012 and December 31, 2011, respectively.

⁴  At September 30, 2012 and December 31, 2011, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $42 million and $22 million, respectively.

⁵  Excludes net receivables of $8 million and $25 million at September 30, 2012 and December 31, 2011, respectively, of interest and dividend receivables as well as receivables and payables related to pending securities sales and purchases.

⁶  Excludes other investments of $70 million and $81 million at September 30, 2012 and December 31, 2011, respectively, primarily related to the cash surrender value of company owned life insurance investments which are used to fund certain executive benefits including deferred compensation. Also excludes other investments of $77 million and $118 million at September 30, 2012 and December 31, 2011, respectively, primarily related to leveraged leases.

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

	Three months ended September 30,								Nine months ended September 30,
(in millions)	2012				2011				2012				2011
Fair value of net assets (liabilities) at beginning of period	$	(343	)		$	(275	)		$	(323	)		$	97
Total realized/unrealized gains (losses):
Included in earnings1	12				(4		)		20				14
Included in regulatory assets and liabilities2	(124		)	3	162			3	(140		)	3	(220		)	3
Included in accumulated other comprehensive income4	(1		)		1				1				(2		)
Purchases	41				24				111				51
Settlements	(73		)		(8		)		(106		)		(38		)
Transfers into Level 3	—				—				—				—
Transfers out of Level 35	—				—				(51		)		(2		)
Fair value of net liabilities at end of period	$	(488	)		$	(100	)		$	(488	)		$	(100	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period6	$	(173	)		$	(110	)		$	(181	)		$	(425	)

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  Included in reclassification adjustments in Edison International's consolidated statements of other comprehensive income.

⁵  Transfers out of Level 3 into Level 2 occurred due to significant observable inputs becoming available as the transactions near maturity.

⁶  Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income was a loss of $7 million for three months ended September 30, 2012, and a gain of $7 million for the nine months ended September 30, 2011. The remainder of the unrealized losses relate to SCE. See 2 above.

The fair value for transfers in and transfers out of each level is determined at the end of each reporting period. There were no transfers between Levels 1 and 2 during the three- and nine-month periods ended September 30, 2012 and 2011.

Valuation Techniques Used to Determine Fair Value

Level 1

The fair value of Level 1 assets and liabilities is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. This level includes exchange-traded equity securities and derivatives, U.S. treasury securities and money market funds.

Level 2

The fair value of Level 2 assets and liabilities is determined using the income approach by obtaining quoted prices for similar assets and liabilities in active markets and inputs that are observable, either directly or indirectly, for substantially the full term of the instrument. This level includes fixed income securities, over-the-counter derivatives and interest rate swaps. For further discussion on fixed income securities, see "—Nuclear Decommissioning Trusts" below.

Over-the-counter derivative contracts are valued using standard pricing models to determine the net present value of estimated future cash flows. 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 price source that best represents trade activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes, prices from exchanges or comparison to executed trades are used to validate and corroborate the primary price 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.

Level 3

The fair value of Level 3 assets and liabilities is determined using the income approach through various models and techniques that require significant unobservable inputs. This level includes over-the-counter options, tolling arrangements and derivative contracts that trade infrequently such as congestion revenue rights ("CRRs") and long-term power agreements.

Assumptions are made in order to value derivative contracts in which observable inputs are not available. Changes in fair value are based on changes to forward market prices, including extrapolation of short-term observable inputs into forecasted prices for illiquid forward periods. In circumstances where fair value cannot be verified with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. Modeling methodologies, inputs and techniques are reviewed and assessed as markets continue to develop and more pricing information becomes available and the fair value is adjusted when it is concluded that a change in inputs or techniques would result in a new valuation that better reflects the fair value of those derivative contracts.

Level 3 Valuation Process

The process of determining fair value is the responsibility of Edison International's subsidiaries' risk management, departments, which report to their respective chief financial officer. These departments obtain observable and unobservable inputs through broker quotes, exchanges and internal valuation techniques that use both standard and proprietary models to determine fair value. Each reporting period, the risk and finance departments collaborate to determine the appropriate fair value methodologies and classifications for each derivative. Inputs are validated for reasonableness by comparison against prior prices, other broker quotes and volatility fluctuation thresholds. Inputs used and valuations are reviewed period-over-period and compared with market conditions to determine reasonableness.

The following table sets forth the valuation techniques and significant unobservable inputs used to determine fair value for Level 3 assets and liabilities at September 30, 2012:

	Fair Value (in millions)							Significant	Range
	Assets			Liabilities			Valuation Technique(s)	Unobservable Input	(Weighted Average)
Electricity:
Options	$	23		$	26		Option model	Volatility of gas prices	23% - 41% (31%)
								Volatility of power prices	28% - 60% (39%)
								Power prices	$38.10 - $58.80 ($45.30)
Forwards	15			20			Discounted cash flow	Power prices	$18.25 - $64.50 ($34.57)
Congestion contracts	100			—			Market simulation model	Load forecast	7,597 MW - 26,612 MW
								Power prices	$(13.90) - $226.75
								Gas prices	$2.95 - $7.78
Congestion contracts	62			24			Latest auction pricing	Congestion prices	$(5.39) - $11.87 ($0.13)
Gas options	—			6			Option model	Volatility of gas prices	24% - 41% (35%)
Tolling	5			617			Option model	Volatility of gas prices	17% - 41% (21%)
								Volatility of power prices	26% - 60% (28%)
								Power prices	$33.20 - $100.80 ($56.10)
Netting	(53		)	(53		)
Total derivative contracts	$	152		$	640

Level 3 Fair Value Sensitivity

Gas Options, Electricity Options, and Tolling Arrangements

The fair values of option contracts and tolling arrangements contain intrinsic value and time value. Intrinsic value is the difference between the market price and strike price of the underlying commodity. Time value is made up of several components, including volatility, time to expiration, and interest rates. The fair value of option contracts changes as the underlying commodity price moves away or towards the strike price. The option model for tolling arrangements reflects plant specific information such as operating and start-up costs.

For tolling arrangements and certain gas and power option contracts where Edison International subsidiaries are the buyer, increases in volatility of the underlying commodity prices would result in increases to fair value as it represents greater price movement risk. As power and gas prices increase, the fair value of the option contracts and tolling arrangements tends to increase. The valuation of power option contracts and tolling arrangements is also impacted by the correlation between gas and power prices. As the correlation increases, the fair value of power option contracts and tolling arrangements tends to decline.

Forward Power Contracts

Generally, an increase (decrease) in long-term forward power prices at illiquid locations where Edison International subsidiaries are the seller relative to the contract price will decrease (increase) fair value. Inversely as a buyer, an increase (decrease) in long-term forward power prices at illiquid locations relative to the contract price will increase (decrease) fair value.

Congestion Contracts

When valuation is based on a discounted cash flow model and Edison International subsidiaries are the buyer, generally an increase (decrease) in congestion prices in the last auction relative to the contract price will increase (decrease) fair value.

When valuation is based on a market simulation model and Edison International subsidiaries are the buyer, generally increases (decreases) in forecasted load would result in increases (decreases) to fair value. In general, increases (decreases) in electricity and gas prices at illiquid locations tends to result in increases (decreases) to fair value; however, changes in electricity and gas prices in opposite directions may have varying results on fair value.

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, 2012				December 31, 2011
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current portion	$	14,273	$	14,452	$	13,746	$	14,264

Fair value of short-term and long-term debt is classified as Level 2 and 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 of new issue prices and relevant credit information.

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

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Other Income and Expenses

9 Months Ended

Sep. 30, 2012

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)	2012		2011		2012		2011
Other income:
Equity allowance for funds used during construction	$	23	$	18	$	71	$	74
Increase in cash surrender value of life insurance policies	6		6		20		19
Other	7		2		12		10
Total utility other income	36		26		103		103
Competitive power generation and other income	1		1		2		7
Total other income	$	37	$	27	$	105	$	110
Other expenses:
Civic, political and related activities and donations	$	5	$	6	$	22	$	21
Other	4		4		14		14
Total utility other expenses	9		10		36		35
Competitive power generation and other expenses	1		1		—		2
Total other expenses	$	10	$	11	$	36	$	37

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Supplemental Cash Flows Information

9 Months Ended

Sep. 30, 2012

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)	2012			2011
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	550		$	529
Tax refunds – net	(71		)	(330		)
Noncash investing and financing activities:
Details of debt exchange:
Pollution-control bonds redeemed	$	—		$	(86	)
Pollution-control bonds issued	—			86
Dividends declared but not paid:
Common stock	$	106		$	104
Preferred and preference stock	6			12

Accrued capital expenditures at September 30, 2012 and 2011 were $431 million and $393 million, respectively. Accrued capital expenditures will be included as an investing activity in the consolidated statements of cash flow in the period paid.

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Compensation and Benefit Plans

9 Months Ended

Sep. 30, 2012

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Compensation and Benefit Plans

Compensation and Benefit Plans

Pension Plans

As part of the pension funding provisions contained in the Surface Transportation Extension Act of 2012 passed by Congress, Edison International's projected 2012 plan contributions have been reduced to $180 million from $286 million, which resulted in a third quarter regulatory adjustment reflected in the table below. Contributions of $156 million were made during the nine months ended September 30, 2012. The 2012 GRC proposed decision authorized contributions of $168 million with recovery of any undercollection through the continuation of the existing balancing account mechanism. A final GRC decision is expected by year-end. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.

Expense components are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Service cost	$	49		$	43		$	135		$	129
Interest cost	49			52			147			156
Expected return on plan assets	(56		)	(60		)	(174		)	(180		)
Amortization of prior service cost	1			2			3			6
Amortization of net loss	21			6			57			18
Expense under accounting standards	64			43			168			129
Regulatory adjustment (deferred)	(57		)	(6		)	(3		)	(18		)
Total expense recognized	$	7		$	37		$	165		$	111

Postretirement Benefits Other Than Pensions

Edison International made contributions of $17 million during the nine months ended September 30, 2012 and expects to make $48 million of additional contributions during the remainder of 2012. In 2012, annual contributions made to plans for SCE employees are expected to be recovered through CPUC-approved regulatory mechanisms. Annual contributions are expected to be, at a minimum, equal to the total annual expense for these plans. Benefits under these plans, with some exceptions, are generally unvested and subject to change.

Expense components are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Service cost	$	13		$	11		$	39		$	33
Interest cost	30			33			90			99
Expected return on plan assets	(27		)	(28		)	(81		)	(84		)
Special termination benefits1	3			—			3			—
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss	12			9			36			27
Total expense	$	22		$	16		$	60		$	48

¹  Due to the reduction in the workforce at San Onofre, Edison International has incurred costs for enhanced retiree health care coverage. See below for further information.

San Onofre Workforce Reduction

In August 2012, SCE announced plans for downsizing to bring the San Onofre organization and cost structure in line with industry peers. SCE plans to reduce the San Onofre workforce by 730 employees to 1,500 employees beginning in the fourth quarter of 2012 and continuing in 2013. At September 30, 2012, SCE had recorded $30 million in estimated cash severance costs (SCE's share) related to the non-represented employee workforce reduction.

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Preferred and Preference Stock of Utility (Details) (Southern California Edison, USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 6.25% Series E	Jun. 30, 2012 5.625% Series F	Jun. 30, 2012 Series A
Preferred and Preference Stock of Utility
Shares issued (in shares)	350,000	190,004
Preference stock (as a percent)	6.25%	5.625%
Preference share, liquidation value (in dollars per share)	$ 1,000	$ 2,500
Stock redeemed and retired			$ 75

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Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2012

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 customer 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 approved by the 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 energy purchased from and sold to wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities and power purchase agreements.

SCE's natural gas price exposure arises from natural gas purchased for 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, 2012	December 31, 2011
Electricity options, swaps and forwards	GWh	18,304	30,881
Natural gas options, swaps and forwards	Bcf	142	300
Congestion revenue rights	GWh	140,263	166,163
Tolling arrangements	GWh	102,123	104,154

Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at September 30, 2012:

	Derivative Assets									Derivative Liabilities1
(in millions)	Short-Term			Long-Term			Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	55		$	80		$	135		$	177		$	1,002		$	1,179		$	1,044
Netting and collateral	(18		)	(6		)	(24		)	(49		)	(19		)	(68		)	(44		)
Total	$	37		$	74		$	111		$	128		$	983		$	1,111		$	1,000

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, 2011:

	Derivative Assets									Derivative Liabilities
(in millions)	Short-Term			Long-Term			Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	86		$	85		$	171		$	303		$	856		$	1,159		$	988
Netting and collateral	(21		)	(15		)	(36		)	(37		)	(51		)	(88		)	(52		)
Total	$	65		$	70		$	135		$	266		$	805		$	1,071		$	936

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 purchase power costs recovered from customers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from customers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.

The following table summarizes the components of economic hedging activity:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Realized gains (losses)	$	(77	)	$	(58	)	$	(199	)	$	(132	)
Unrealized gains (losses)	(91		)	(110		)	(29		)	(433		)

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 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 $113 million and $216 million as of September 30, 2012 and December 31, 2011, respectively, for which SCE has posted no collateral to its counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2012, SCE would be required to post $25 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. Substantially all of the contracts that SCE has executed with counterparties are either entered into under SCE's procurement plan which has been pre-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's subsidiary, EME uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, transmission rights and 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 EME does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements.

Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not designated as cash flow hedges. Economic hedges are accounted for at fair value on the consolidated balance sheets as derivative assets or liabilities with offsetting changes recorded on the consolidated statements of operations. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized on the consolidated balance sheets as derivative assets or liabilities with offsetting changes in fair value, to the extent effective, recognized in accumulated other comprehensive loss until reclassified into earnings when the related forecasted transaction occurs. The portion of a cash flow hedge that does not offset the change in the fair value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings.

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, with offsetting changes recognized in operating revenues on the consolidated statements of operations.

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

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

Notional Volumes of Derivative Instruments

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

September 30, 2012
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges	Economic Hedges		Trading Activities
Electricity	Forwards/Futures	Sales, net	GWh	5,644	58	2	—
Electricity	Forwards/Futures	Purchases, net	GWh	—	—		550
Electricity	Capacity	Purchases, net	GW-Day	—	—		97	1
Electricity	Congestion	Purchases, net	GWh	—	241	3	281,251	3
Natural gas	Forwards/Futures	Sales, net	bcf	—	—		0.4
Fuel oil	Forwards/Futures	Sales, net	barrels	—	—		100,000
Fuel oil	Forwards/Futures	Purchases, net	barrels	—	120,000		—

At September 30, 2012, EME had interest rate contracts with notional values totaling $727 million that converted floating rate LIBOR-based debt to fixed rates ranging from 0.79% to 4.29%. These contracts expire May 2013 through March 2026. In addition, at September 30, 2012, EME had forward starting interest rate contracts with notional values totaling $641 million that will convert floating rate LIBOR-based debt to fixed rates ranging from 0.7825% to 4.0025%. These contracts have effective dates beginning December 2012 through December 2021 and expire December 2013 through December 2029.

December 31, 2011
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges		Economic Hedges		Trading Activities
Electricity	Forwards/Futures	Sales, net	GWh	8,320		335	2	—
Electricity	Forwards/Futures	Purchases, net	GWh	—		—		2,926
Electricity	Capacity	Sales, net	GW-Day	61	1	—		—
Electricity	Capacity	Purchases, net	GW-Day	—		—		184	1
Electricity	Congestion	Purchases, net	GWh	—		1,261	3	230,798	3
Natural gas	Forwards/Futures	Sales, net	bcf	—		—		0.2
Fuel oil	Forwards/Futures	Purchases, net	barrels	—		240,000		—

¹  EME's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM Interconnection, LLC Reliability Pricing Model (PJM RPM) auction is not accounted for as a derivative.

²  These positions adjust financial and physical positions, or day-ahead and real-time positions, to reduce costs or increase gross margin. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.

³  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.

At December 31, 2011, EME had interest rate contracts with notional values totaling $644 million that converted floating rate LIBOR-based debt to fixed rates ranging from 0.79% to 4.29%. These contracts expire May 2013 through March 2026. In addition, EME had forward starting interest rate contracts with notional values totaling $506 million that will convert floating rate LIBOR-based debt to fixed rates of 3.5429%, 3.57% and 4.0025%. These contracts have effective dates of June 2013 and December 2021 and expire May 2023 and December 2029.

Fair Value of Derivative Instruments

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

September 30, 2012
	Derivative Assets									Derivative Liabilities
(in millions)	Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal			Net Assets (Liabilities)
Non-trading activities
Cash flow hedges
Commodity contracts	$	14		$	2		$	16		$	9		$	1		$	10		$	6
Interest rate contracts	—			—			—			—			125			125			(125		)
Economic hedges	25			1			26			23			1			24			2
Trading activities	321			145			466			265			98			363			103
	360			148			508			297			225			522			(14		)
Netting and collateral received1	(321		)	(105		)	(426		)	(296		)	(100		)	(396		)	(30		)
Total	$	39		$	43		$	82		$	1		$	125		$	126		$	(44	)

December 31, 2011
	Derivative Assets									Derivative Liabilities
(in millions)	Short-term			Long-term			Subtotal			Short-term			Long-term			Subtotal			Net Assets (Liabilities)
Non-trading activities
Cash flow hedges
Commodity contracts	$	40		$	1		$	41		$	2		$	—		$	2		$	39
Interest rate contracts	—			—			—			—			90			90			(90		)
Economic hedges	24			—			24			20			—			20			4
Trading activities	277			142			419			232			79			311			108
	341			143			484			254			169			423			61
Netting and collateral received1	(301		)	(81		)	(382		)	(253		)	(79		)	(332		)	(50		)
Total	$	40		$	62		$	102		$	1		$	90		$	91		$	11

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,
	2012						2011
(in millions)	Commodity Contracts			Interest Rate Contracts			Commodity Contracts			Interest Rate Contracts			Income Statement Location
Beginning of period derivative gains (losses)	$	35		$	(90	)	$	43		$	(16	)
Effective portion of changes in fair value	3			(35		)	2			(64		)
Reclassification to earnings	(31		)	—			(29		)	—			Competitive power generation revenue
End of period derivative gains (losses)	$	7		$	(125	)	$	16		$	(80	)

¹  Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive loss at September 30, 2012 and 2011 for commodity and interest rate contracts were $7 million and $(79) million, and $10 million and $(49) million, respectively.

For additional information, see Note 11.

EME recorded gains (losses) of $(2) million and $2 million during the three months ended September 30, 2012 and 2011, respectively, and gains of none and $2 million during the nine months ended September 30, 2012 and 2011, respectively, in operating revenues on the consolidated statements of income representing the amount of cash flow hedge ineffectiveness.

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

		Three months ended September 30,					Nine months ended September 30,
(in millions)	Income Statement Location	2012		2011			2012		2011
Economic hedges	Competitive power generation revenues	$	8	$	(3	)	$	25	$	5
	Fuel	3		(3		)	2		1
Trading activities	Competitive power generation revenues	22		11			72		68

Contingent Features

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's and its subsidiaries' credit ratings are below investment grade, EME and its subsidiaries have provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties.

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, 2012		December 31, 2011
Collateral provided to counterparties:
Offset against derivative liabilities	$	54	$	53
Reflected in margin and collateral deposits	88		58
Collateral received from counterparties:
Offset against derivative assets	39		53

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Income Taxes

9 Months Ended

Sep. 30, 2012

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.

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Income from continuing operations before income taxes	$	477		$	658		$	781		$	1,218
Provision for income tax at federal statutory rate of 35%	167			230			273			426
Increase (decrease) in income tax from:
State tax – net of federal benefit	60			28			56			40
Production and housing credits	(12		)	(12		)	(48		)	(48		)
Property-related	(20		)	(18		)	(39		)	(38		)
Other	(14		)	4			(25		)	(10		)
Total income tax expense from continuing operations	$	181		$	232		$	217		$	370
Effective tax rate	38		%	35		%	28		%	30		%

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

The following table provides a reconciliation of unrecognized tax benefits:

(in millions)	2012			2011
Balance at January 1,	$	631		$	565
Tax positions taken during the current year:
Increases	22			53
Tax positions taken during a prior year:
Increases	207			60
Decreases	(29		)	(37		)
Decreases for settlements during the period	—			—
Balance at September 30,	$	831		$	641

As of September 30, 2012 and December 30, 2011, respectively, if recognized, $578 million and $532 million of the unrecognized tax benefits would impact the effective tax rate.

Tax Dispute

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 EME's international assets, which if sustained, would result in a federal tax payment of approximately $198 million, including interest and penalties through September 30, 2012 (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 $95 million, including interest through September 30, 2012.

Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011. The appeals process to date has not resulted in a change in the proposed adjustment by the IRS on the taxable gain on the 2004 sale of EME's international assets. If a deficiency notice is issued on this item, it would require payment of the tax, interest and any penalties within 90 days of its issuance or a filing of a petition in United States Tax Court.

Tax Election at Homer City

On March 15, 2012, Homer City made an election to be treated as a partnership for federal and state income tax purposes. As a result of this election, Homer City is treated for tax purposes as distributing its assets and liabilities to its partners, both of which are wholly owned subsidiaries of EME, and triggering tax deductions of approximately $1.0 billion. Such tax deductions were included in Edison International's 2011 consolidated tax returns.

Loss and Credit Carryforwards

Including the tax deduction generated from the Homer City election, Edison International has recorded tax benefits for federal and state net operating loss carryforwards and federal tax credit carryforwards of approximately $1.6 billion as of September 30, 2012.

Repair Deductions

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. In August 2011, the IRS issued guidance on repair deductions and changes in accounting method related to transmission and distribution assets. Based on this guidance, SCE included a second change in tax accounting method on repair costs in its 2011 tax return. Guidance for generation assets is pending. Regulatory treatment for the incremental deductions taken after the voluntary election to change SCE's tax accounting method for certain repair costs is part of SCE's 2012 GRC. Due to the pending regulatory decision, SCE has not recognized an earnings benefit or regulatory asset related to this method change and incremental deductions taken in 2009, 2010 and 2011. In October 2012, the CPUC assigned administrative law judge issued a proposed GRC decision, which if adopted, would result in an earnings benefit of approximately $230 million attributable to flow through treatment of 2009 – 2011 vintage year activity. SCE would also record an earnings benefit related to 2012 vintage year activity consistent with the rate making treatment.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Third-Party Power Purchase Agreements

During the nine months ended September 30, 2012, SCE had power purchase contracts with additional commitments estimated to be: $17 million in 2014, $43 million in 2015, $66 million in 2016 and $970 million for the period remaining thereafter. Some of these power purchase agreements are classified as operating leases. The additional commitments for these leases, which are also included in the amounts above, are estimated to be: $21 million in 2015, $45 million in 2016 and $942 million for the period remaining thereafter.

Coal Transportation Agreements

At September 30, 2012, Midwest Generation had contractual agreements for the transportation of coal. The commitments under these contracts are based on either actual coal purchases derived from committed coal volumes set forth in fuel supply contracts or minimum quantities as set forth in the transportation agreements as adjusted for provisions that mitigate the financial exposure of Midwest Generation related to a plant closure under certain circumstances as specified in the agreements. Estimated contractual obligations for coal transportation agreements are estimated to aggregate $2.3 billion, which consists of: $118 million for the remainder of 2012, $292 million for 2013, $286 million for 2014, $260 million for 2015, $260 million for 2016 and $1.1 billion thereafter. Years subsequent to 2012 reflect a reduction in minimum volumes for the shutdown of the Fisk and Crawford Stations.

Capital Commitments

At September 30, 2012, EMG's subsidiaries had firm commitments to spend approximately $92 million during the remainder of 2012, $44 million for 2013 and $17 million for 2015 for capital expenditures. These expenditures primarily relate to the Walnut Creek project, construction of wind projects and capital expenditures at the Midwest Generation plants.

Homer City Lease

Homer City received a forbearance of the $47 million senior rent payment due October 1, 2012. Homer City made the required April 1, 2012 senior rent payment of $48 million but did not make the April 1, 2012 payment of equity rent of $65 million and was granted a waiver by the owner-lessors of any rent default event with respect to the payment of the equity rent for all purposes other than restrictions on distributions from Homer City, including repayment of its intercompany loan, and the $48 million senior rent reserve letter of credit remains in place. Homer City and an affiliate of GECC entered into the Homer City MTA for the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities. For further discussion, see Note 18.

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 owner-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," and one of the Powerton-Joliet owner-lessors has made a similar request for indemnification. Commonwealth Edison has also advised EME that it believes it is entitled to indemnification for costs and expenses incurred in connection with the information requested under the Comprehensive Environmental Response, Compensation and Liability Act of 1980 regarding environmental sampling and investigation performed at Midwest Generation's Fisk and Crawford sites. 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, the supplemental agreement has been extended until February 2013. There were approximately 230 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at September 30, 2012. Midwest Generation had recorded a liability of $53 million at September 30, 2012 related to this contractual indemnity.

Indemnities Related to the Homer City Plant

In connection with the original 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 owner-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, 2012, EME had recorded a liability of $20 million related to these matters.

In connection with the sale-leaseback transactions related to the Homer City plant in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Under certain of these tax indemnity agreements, Homer City and Midwest Generation, as the lessees in the sale-leaseback transactions agreed to indemnify the respective owner-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 range of estimated obligations which would be triggered by a valid claim from the owner-lessors. EME has not recorded a liability for these matters.

In addition to the indemnity provided by Homer City, EME agreed to indemnify the owner-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 owner-lessor's debt is characterized as recourse, rather than nonrecourse. This indemnity covers a limited range of possible tax consequences that are unrelated to performance under the lease.

Upon closing of the Homer City MTA, the tax indemnity agreements between EME, Homer City and GECC will be terminated and GECC will release EME and Homer City from its obligations thereunder. Completion of the Homer City MTA is subject to the satisfaction of a number of closing conditions, including the successful restructuring and reorganization of an affiliate of GECC and receipt of the regulatory approvals required for the transfer of the Homer City plant to GECC. For further discussion, see Note 18.

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

SCE has indemnified the City of Redlands, California in connection with Mountainview's California Energy Commission permit 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 and Guarantees

EME guarantees Midwest Generation's payments under the Powerton and Joliet sale-leaseback agreements. A default by Midwest Generation in meeting its obligations under those agreements could have an adverse impact on EME.

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, individually or in the aggregate, 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 called for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at all units subject to the complaint and other remedies. 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 intervened in the case.

Nine of the ten PSD claims raised in the complaint 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, and 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. The dismissals have been certified as "partial final judgments" capable of appeal, and an appeal is pending before the Seventh Circuit Court of Appeals. The remaining claims have been stayed pending the appeal. In February 2012, certain of the environmental action groups that had intervened in the case entered into an agreement with Midwest Generation to dismiss without prejudice all of their opacity claims as to all defendants. The agreed upon motion to dismiss was approved by the court on March 26, 2012.

In January 2012, two complaints were filed against Midwest Generation in Illinois state court by residents living near the Crawford and Fisk Stations on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs seek to have their suits certified as a class action and request injunctive relief, as well as compensatory and punitive damages. The complaints are similar to two complaints previously filed in the Northern District of Illinois, which were dismissed in October 2011 for lack of federal jurisdiction. Midwest Generation's motions to dismiss the cases were denied in August 2012, following which the plaintiffs filed amended complaints alleging substantially similar claims and requesting similar relief.

In October 2012, Midwest Generation and the Illinois Environmental Protection Agency entered into Compliance Commitment Agreements outlining specified environmental remediation measures and groundwater monitoring activities to be undertaken at its Powerton, Joliet, Crawford, Will County and Waukegan generating stations. Also in October 2012, several environmental groups filed a complaint before the Illinois Pollution Control Board against Midwest Generation, alleging violations of the Illinois groundwater standards through the operation of coal ash disposal ponds at its Powerton, Joliet, Waukegan and Will County generating stations. The complaint requests the imposition of civil penalties, injunctive relief and remediation.

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 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. EME has not recorded a liability for these matters.

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 PADEP, the State of New York and the State of New Jersey intervened in the lawsuit. In October 2011, all of the claims in the US EPA's lawsuit were dismissed with prejudice. An appeal of the dismissal is pending before the Third Circuit Court of Appeals.

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. In October 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 plaintiffs will file a complaint in state court.

In February 2012, Homer City received a 60-day Notice of Intent to Sue indicating the Sierra Club’s intent to file a citizen lawsuit alleging violations of emissions standards and limitations under the CAA and the Pennsylvania Air Pollution Control Act.

Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material impact on the financial condition and results of operations of Homer City and EME. EME cannot predict the outcome of these matters or estimate the impact on the Homer City plant, or its and Homer City's results of operations, financial position or cash flows. EME has not recorded a liability for these matters.

San Onofre Outage, Inspection and Repair Issues

SCE replaced four steam generators at San Onofre Units 2 and 3 in 2010 and 2011, respectively. In the first quarter of 2012, a water leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. Unit 3 was safely taken off-line. At the time, San Onofre Unit 2 was off-line for a planned outage when areas of unexpected wear in some of its heat transfer tubes were found. Both Units have remained off-line for extensive inspections, testing and analysis of their steam generators. Each Unit will be restarted only when and if SCE determines that it is safe to do so and when start-up has been approved by the NRC pursuant to the terms of a Confirmatory Action Letter (“CAL”) issued by the NRC in March 2012. The CAL requires NRC permission to restart Unit 2 and Unit 3 and outlines actions SCE must complete before permission to restart either Unit may be sought. In October 2012, SCE submitted to the NRC a response to the CAL and restart plans for Unit 2. SCE proposed to restart Unit 2 and operate at a reduced power level (70%) for approximately five months, followed by a mid-cycle scheduled outage.

In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million after adjustment for inflation) for SCE's 78.21% share of San Onofre to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $594 million through September 30, 2012 on the steam generator replacement project, including $95 million reflected in construction work in progress primarily related to the disposal of the replaced steam generators. Those expenditures remain subject to CPUC reasonableness review. Final costs for the project will not be known until after disposal of the original steam generators is completed.

As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre are being purchased in the market by SCE (commencing on February 1 for Unit 3 and March 5 for Unit 2). Market costs through September 30, 2012 were approximately $221 million, net of avoided nuclear fuel costs, and are recoverable through the ERRA balancing account subject to CPUC reasonableness review. Because of the uncertainties associated with when and at what output levels the Units will or may be returned to service, total potential market power costs cannot be estimated at this time.

Through September 2012, SCE's share of incremental inspection and repair costs totaled $96 million for both Units. At September 30, 2012, the repairs to restart Unit 2 at the reduced power levels described above have been substantially completed. The costs for Unit 2 may increase following NRC review under the CAL and any new developments that may result from further analysis, testing and inspection, and there is no assurance that start-up of Unit 2 will occur as described above. Total incremental repair costs associated with returning Unit 3 to service, and returning both Units to service at originally specified capabilities safely, remain uncertain.

In addition to the amounts for inspection and repair and market power costs discussed below, SCE has collected through customer rates an estimated $625 million of revenue through third quarter 2012 (based on current authorized revenue requirements) associated with the plant. SCE's total 2012 San Onofre annual revenue requirement, including the 2012 GRC proposed decision, is approximately $820 million, made up of $170 million in refueling outage, nuclear fuel and decommissioning costs and $650 million for its direct operating and maintenance costs, depreciation and return on its investment in San Onofre Unit 2, Unit 3 and related common plant. At September 30, 2012, SCE's rate base and net investment and inventory associated with San Onofre was $1.2 billion and $2.1 billion, respectively.

Under California Public Utilities Code Section 455.5, SCE is required to notify the CPUC if either of the San Onofre Units has been out of service for nine consecutive months (not including preplanned outages). SCE will provide such notice to the CPUC on November 1, 2012 for Unit 3 and expects to do so by December 6, 2012 for Unit 2. The CPUC is required within 45 days of SCE's notice for a particular Unit to initiate an investigation to determine whether to remove from customer rates some or the entire revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such rates are collected subject to refund. Under Section 455.5 any determination to adjust rates is made after hearings are conducted in connection with the utility's next general rate case. If, after investigation and hearings, the costs associated with a Unit are disallowed recovery because it is out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation.

In October 2012, in advance of SCE's required notification under Section 455.5, the CPUC issued an order instituting investigation ("OII") that will consolidate all San Onofre issues in related regulatory proceedings and consider appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, market power costs, capital and operations and maintenance costs, and seismic study costs. The order requires that all San Onofre-related costs incurred on and after January 1, 2012 be tracked in a memorandum account and, to the extent included in rates, collected subject to refund. The order also states that the CPUC will determine whether to order the immediate removal, effective as of the date of the order, of all costs related to San Onofre from SCE's rates, with placement of those costs in a deferred debit account pending the return of one or both Units to useful service, or other possible action. SCE will file its response to the order by November 26, 2012. SCE must also file testimony by December 10, 2012 detailing proposed rate adjustments due to the outages, including the amount of San Onofre costs in current rates, the amount to be removed, if any, the effective date, and related information. A pre-hearing conference will be scheduled early in 2013 after the issuance of a Scoping Memo by the Assigned Commissioner.

In parallel with the order instituting investigation, the 2012 GRC proposed decision would, if adopted, require SCE to track San Onofre-related costs in a memorandum account subject to refund, beginning January 1, 2012. SCE would be required by January 30, 2013 to file an application for reasonableness review of these costs and the proposed decision would allow that application to be consolidated with other proceedings. The 2012 GRC proposed decision also approves expenditures incurred through 2011 for the high pressure turbine project, but disallows recovery for post-2011 expenditures associated with the project and directs SCE to record those costs in either the memorandum account or seek future rate recovery in the next GRC. SCE anticipates that the inter-relationship between the Section 455.5 process and the issues to be reviewed in the investigation or pursuant to a final decision in the GRC will be addressed by the CPUC as it continues to develop the scope of the issues to be consolidated within the investigation.

The steam generators were designed and supplied by MHI and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. SCE's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include "the cost of replacement power." Such limitations in the contract are subject to applicable exceptions. In September 2012, SCE submitted an invoice to MHI for costs paid through June 30, 2012 in the amount of $45 million for both SCE's and the other co-owners' share of steam generator repair costs. SCE expects to continue to invoice MHI for costs incurred. No amounts have been recognized in the financial statements as of September 30, 2012.

San Onofre carries both property damage and outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of potential claims for loss recovery. In October 2012, SCE filed separate proofs of loss for Unit 2 and Unit 3 under the outage policy. Pursuant to these proofs of loss SCE is seeking the weekly indemnity amounts provided under the policy for each Unit. Because the outage is ongoing, SCE will supplement these proofs of loss in the future. No amounts have been recognized in SCE's financial statements, pending further actions by NEIL. To the extent any costs are recovered under the outage policy, SCE expects to refund those amounts to ratepayers through the ERRA balancing account.

SCE will pursue recoveries arising from available agreements, but there is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements.

CPSD Investigations

San Gabriel Valley Windstorm Investigation

In November 2011, a windstorm resulted in significant damage to SCE’s electric system and service outages for SCE customers primarily in the San Gabriel Valley. The CPUC directed its Consumer Protection and Safety Division (“CPSD”) to conduct an investigation focused on the cause of the outages, SCE’s service restoration effort, and SCE’s customer communications during the outages. The CPSD issued its preliminary report on February 1, 2012. The report asserts that SCE and others with whom SCE shares utility poles violated certain CPUC safety rules applicable to overhead line construction, maintenance and operation, which may have caused the failures of affected poles and supporting cables. The report also concludes that SCE’s restoration time was not adequate and makes other assertions. Additionally, the report contends that SCE violated CPUC rules by failing to preserve evidence relevant to the investigation when it did not retain damaged poles that were replaced following the windstorm. If the CPUC issues an OII regarding this matter and SCE is found to have violated any CPUC rules, it could face penalties. SCE is unable to estimate a possible loss or range of loss associated with any penalties that may be imposed by the CPUC on SCE.

The proposed decision in SCE’s 2012 GRC would direct SCE to, among other things, make an assessment of a representative sampling of its loaded poles to determine their conformance with current legal standards and report by January 31, 2013 on the results of this assessment. The cost of any large scale review of poles or other equipment for safety compliance, as well as any remediation measures required to assure compliance, could be significant.

Malibu Fire Order Instituting Investigation

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 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. In September 2012, the CPUC approved a partial settlement between the CPSD and three telecomm providers, leaving SCE and a non-settling telecomm provider as the remaining respondents. The partial settlement did not resolve any of the claims against SCE or the remaining telecomm provider.

Four Corners New Source Review Litigation

In October 2011, four private environmental organizations filed a CAA citizen 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” and the plant's failure to obtain permits and install best available control technology ("BACT") violated the PSD requirements and the New Source Performance Standards of the CAA. The complaint also alleges subsequent and continuing violations 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 certain closing conditions, including APS obtaining a long-term fuel supply agreement for the plant, and is expected to close no earlier than December 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 is unable to estimate a possible loss or range of loss associated with this matter.

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, operation 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.

At September 30, 2012, Edison International's recorded estimated minimum liability to remediate its 27 identified material sites (sites in which the upper end of the range of the costs is at least $1 million) at SCE (25 sites) and EME (2 sites related to Midwest Generation) was $121 million, of which $113 million was related to SCE, including $78 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. Of the $116 million total environmental remediation liability for SCE, $113 million has been recorded as a regulatory asset. SCE expects to recover $31 million through an incentive mechanism that allows SCE to recover 90% of its environmental remediation costs at certain sites (SCE may request to include additional sites) and $82 million through a mechanism that allows SCE to recover 100% of the costs incurred at certain sites 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.

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 the identified material sites and immaterial sites could exceed its recorded liability by up to $185 million and $6 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.

SCE expects to clean up and mitigate its identified sites over a period of up to 30 years. Remediation costs for 2012 and in each of the next four years are expected to range from $7 million to $14 million. Costs incurred for the nine months ended September 30, 2012 and 2011 were $5 million and $9 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.

NEIL, a mutual insurance company owned by entities with nuclear facilities, issues primary property damage, decontamination and excess property damage and accidental outage insurance policies. At San Onofre and Palo Verde, property damage insurance covers losses up to $500 million, including decontamination costs. Decontamination liability and excess property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than the federal requirement of a minimum of approximately $1.1 billion. Property damage insurance also covers damages caused by acts of terrorism up to specified limits. Additional outage insurance covers part of replacement power expenses during an accident-related nuclear unit outage.

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 $49 million per year. Insurance premiums are charged to operating expense.

Wildfire Insurance

Severe wildfires in California have given rise to large damage claims against California utilities for fire-related losses alleged to be the result of the failure of electric and other utility equipment. Invoking a California Court of Appeal decision, plaintiffs pursuing these claims have relied on the doctrine of inverse condemnation, which can impose strict liability (including liability for a claimant's attorneys' fees) for property damage. On September 15, 2012, SCE's parent, Edison International, renewed its insurance coverage, which included coverage for SCE's wildfire liabilities up to a $550 million limit (with a self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up the insurance coverage could result in additional self-insured costs in the event of multiple wildfire occurrences during the policy period (September 15, 2012 to August 31, 2013). SCE may experience coverage reductions and/or increased insurance costs in future years. No assurance can be given that future losses will not exceed the limits of SCE's insurance coverage.

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 the San Onofre 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. SCE received payment from the federal government in the amount of the damage award in November 2011. SCE has returned to the San Onofre co-owners their respective share of the damage award paid. SCE, as operating agent, filed a lawsuit on behalf of the San Onofre owners against the DOE in the Court of Federal Claims in December 2011 seeking damages of approximately $98 million for the period from January 1, 2006 to December 31, 2010 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel. Additional legal action would be necessary to recover damages incurred after December 31, 2010. Any damages recovered by SCE are subject to CPUC review as to how these amounts would be distributed among customers, shareholders, or to offset fuel decommissioning or storage costs.

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Other Income and Expenses (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Other income:
Equity allowance for funds used during construction	$ 23	$ 18	$ 71	$ 74
Increase in cash surrender value of life insurance policies	6	6	20	19
Other	7	2	12	10
Total utility other income	36	26	103	103
Competitive power generation and other income	1	1	2	7
Total other income	37	27	105	110
Other expenses:
Civic, political and related activities and donations	5	6	22	21
Other	4	4	14	14
Total utility other expenses	9	10	36	35
Competitive power generation and other expenses	1	1	0	2
Total other expenses	$ 10	$ 11	$ 36	$ 37

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Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended				3 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2012 Homer City	Dec. 31, 2011 Homer City	Oct. 03, 2012 Homer City Plan Support Agreement Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Principal outstanding (as a percent)									76.00%
Impairment and other charges							$ 113	$ 1,030
Other charges to write down assets held for sale to net realizable value, net of tax							68
Summarized results of discontinued operations:
Total operating revenues	121	159	303	409
Total operating expenses	(138)	(134)	(385)	(409)
Asset impairment and other charges	(113)	0	(134)	0
Other income (expense)	5	2	7	(1)
Income (loss) before income taxes	(125)	27	(209)	(1)
Provision (benefit) for income taxes	(49)	12	(80)	2
Income (loss) from operations of discontinued operations	(76)	15	(129)	(3)
Major components of asset and liabilities of discontinued operations:
Cash and cash equivalents	55	104	55	104	79	128
Other current assets	114		114		128
Carrying value adjustment	(108)		(108)		0
Total current assets	61		61		207
Other long-term assets	0		0		45
Assets of discontinued operations	61		61		252
Total current liabilities	61		61		27
Other long-term liabilities	0		0		9
Liabilities of discontinued operations	$ 61		$ 61		$ 36

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Other Investments (Summary of Changes in Fair Value of the Nuclear Decommissioning Trusts) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Summary Of Changes In The Fair Value [Roll Forward]
Balance at beginning of period	$ 3,810	$ 3,657	$ 3,592	$ 3,480
Gross realized gains	13	46	54	81
Gross realized losses	0	(5)	(5)	(5)
Unrealized gains (losses) - net	156	(305)	272	(199)
Other-than-temporary impairments	(7)	(22)	(30)	(35)
Interest, dividends, contributions and other	25	22	114	71
Balance at end of period	$ 3,997	$ 3,393	$ 3,997	$ 3,393

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2012

Income Tax Disclosure [Abstract]

Reconciliation of Income Tax Expense

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)	2012			2011			2012			2011
Income from continuing operations before income taxes	$	477		$	658		$	781		$	1,218
Provision for income tax at federal statutory rate of 35%	167			230			273			426
Increase (decrease) in income tax from:
State tax – net of federal benefit	60			28			56			40
Production and housing credits	(12		)	(12		)	(48		)	(48		)
Property-related	(20		)	(18		)	(39		)	(38		)
Other	(14		)	4			(25		)	(10		)
Total income tax expense from continuing operations	$	181		$	232		$	217		$	370
Effective tax rate	38		%	35		%	28		%	30		%

Reconciliation of Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits:

(in millions)	2012			2011
Balance at January 1,	$	631		$	565
Tax positions taken during the current year:
Increases	22			53
Tax positions taken during a prior year:
Increases	207			60
Decreases	(29		)	(37		)
Decreases for settlements during the period	—			—
Balance at September 30,	$	831		$	641

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Derivative Instruments and Hedging Activities (Balance Sheet Disclosures) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2011
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	$ 76		$ 106
Long-Term, Derivative Assets	117		131
Short-Term, Derivative Liabilities	109		268
Long-Term, Derivative Liabilities	717		547
Electric Utility | Commodity Contracts
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	37	[1]	65
Long-Term, Derivative Assets	74	[1]	70
Derivative Assets, Total	111	[1]	135
Short-Term, Derivative Liabilities	128	[1]	266
Long-Term, Derivative Liabilities	983	[1]	805
Derivative Liabilities, Total	1,111	[1]	1,071
Net Asset (Liability)	(1,000)	[1]	(936)
Electric Utility | Commodity Contracts | Economic hedges
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	55	[1]	86
Long-Term, Derivative Assets	80	[1]	85
Derivative Assets, Total	135	[1]	171
Short-Term, Derivative Liabilities	177	[1]	303
Long-Term, Derivative Liabilities	1,002	[1]	856
Derivative Liabilities, Total	1,179	[1]	1,159
Net Asset (Liability)	(1,044)	[1]	(988)
Electric Utility | Commodity Contracts | Netting and Collateral
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	(18)	[1]	(21)
Long-Term, Derivative Assets	(6)	[1]	(15)
Derivative Assets, Total	(24)	[1]	(36)
Short-Term, Derivative Liabilities	(49)	[1]	(37)
Long-Term, Derivative Liabilities	(19)	[1]	(51)
Derivative Liabilities, Total	(68)	[1]	(88)
Net Asset (Liability)	44	[1]	52
Competitive Power Generation
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	39		40
Long-Term, Derivative Assets	43		62
Derivative Assets, Total	82		102
Short-Term, Derivative Liabilities	1		1
Long-Term, Derivative Liabilities	125		90
Derivative Liabilities, Total	126		91
Net Asset (Liability)	(44)		11
Competitive Power Generation | Trading and Non-trading activities
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	360		341
Long-Term, Derivative Assets	148		143
Derivative Assets, Total	508		484
Short-Term, Derivative Liabilities	297		254
Long-Term, Derivative Liabilities	225		169
Derivative Liabilities, Total	522		423
Net Asset (Liability)	(14)		61
Competitive Power Generation | Economic hedges
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	25		24
Long-Term, Derivative Assets	1		0
Derivative Assets, Total	26		24
Short-Term, Derivative Liabilities	23		20
Long-Term, Derivative Liabilities	1		0
Derivative Liabilities, Total	24		20
Net Asset (Liability)	2		4
Competitive Power Generation | Trading activities
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	321		277
Long-Term, Derivative Assets	145		142
Derivative Assets, Total	466		419
Short-Term, Derivative Liabilities	265		232
Long-Term, Derivative Liabilities	98		79
Derivative Liabilities, Total	363		311
Net Asset (Liability)	103		108
Competitive Power Generation | Netting and Collateral
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	(321)	[2]	(301)	[2]
Long-Term, Derivative Assets	(105)	[2]	(81)	[2]
Derivative Assets, Total	(426)	[2]	(382)	[2]
Short-Term, Derivative Liabilities	(296)	[2]	(253)	[2]
Long-Term, Derivative Liabilities	(100)	[2]	(79)	[2]
Derivative Liabilities, Total	(396)	[2]	(332)	[2]
Net Asset (Liability)	(30)	[2]	(50)	[2]
Competitive Power Generation | Commodity Contracts | Cash flow hedges
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	14		40
Long-Term, Derivative Assets	2		1
Derivative Assets, Total	16		41
Short-Term, Derivative Liabilities	9		2
Long-Term, Derivative Liabilities	1		0
Derivative Liabilities, Total	10		2
Net Asset (Liability)	6		39
Competitive Power Generation | Interest Rate Contracts | Cash flow hedges
Fair Value of Derivative Instruments
Short-Term, Derivative Assets	0		0
Long-Term, Derivative Assets	0		0
Derivative Assets, Total	0		0
Short-Term, Derivative Liabilities	0		0
Long-Term, Derivative Liabilities	125		90
Derivative Liabilities, Total	125		90
Net Asset (Liability)	$ (125)		$ (90)

[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.

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

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Regulatory Assets and Liabilities

9 Months Ended

Sep. 30, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

Regulatory Assets

Regulatory assets included on the consolidated balance sheets are:

(in millions)	September 30, 2012		December 31, 2011
Current:
Regulatory balancing accounts	$	108	$	223
Energy derivatives	141		264
Other	1		7
Total Current	250		494
Long-term:
Deferred income taxes – net	2,148		2,020
Pensions and other postretirement benefits	1,657		1,703
Energy derivatives	573		487
Unamortized investments – net	484		484
Unamortized loss on reacquired debt	233		249
Nuclear-related investment – net	145		156
Regulatory balancing accounts	102		69
Other	335		298
Total Long-term	5,677		5,466
Total Regulatory Assets	$	5,927	$	5,960

Regulatory Liabilities

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	September 30, 2012		December 31, 2011
Current:
Regulatory balancing accounts	$	478	$	661
Other	15		9
Total Current	493		670
Long-term:
Costs of removal	2,745		2,697
Asset Retirement Obligations	1,378		1,105
Regulatory balancing accounts	1,119		864
Other	7		4
Total Long-term	5,249		4,670
Total Regulatory Liabilities	$	5,742	$	5,340

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EME Liquidity and Restructuring Activities

9 Months Ended

Sep. 30, 2012

Restructuring and Related Activities [Abstract]

EME Liquidity and Restructuring Activities

EME Liquidity and Restructuring Activities

At September 30, 2012, EME, and its subsidiaries without contractual dividend restrictions, had corporate cash and cash equivalents of $627 million, which includes Midwest Generation's cash and cash equivalents of $142 million. At September 30, 2012, EME had $3.7 billion of unsecured notes outstanding, $500 million of which mature in June 2013.

EME continues to experience operating losses due to low realized energy and capacity prices, high fuel costs and low generation at the Midwest Generation plants. Forward market prices indicate that these trends are expected to continue for a number of years. As a result, EME expects that it will incur further reductions in cash flow and losses in the current year and in subsequent years. A continuation of these adverse trends coupled with pending debt maturities and the need to retrofit its Midwest Generation plants to comply with governmental regulations will exhaust EME's liquidity. Consequently, EME has been considering all options available to it, including potential sales of assets, restructuring, reorganization of its capital structure, or conservation of cash that would be applied otherwise to the payment of obligations.

In June 2012, EME entered into non-disclosure and engagement agreements with advisors representing holders of a majority in principal amount of its unsecured bonds for the purpose of engaging in discussions with such advisors and Edison International regarding EME's financial condition. In October 2012, EME and Edison International entered into non-disclosure agreements with certain of the clients of such advisors to facilitate further discussions. Discussions with the bondholders' advisors have been ongoing. In addition, EME and Midwest Generation have entered into a non-disclosure agreement with an advisor representing a majority in principal amount of Midwest Generation's senior lease obligation bonds.

Based on current projections, EME is not expected to have sufficient liquidity to repay the $500 million debt obligation due in June 2013. On November 15, 2012, $97 million of interest payments are due on unsecured EME bonds maturing in 2017, 2019 and 2027, and there is no assurance payment will be made. EME's unsecured bonds generally provide for a 30-day grace period for interest payments. EME's failure to pay indebtedness under its unsecured bonds would likely result in EME's filing for protection under Chapter 11 of the U.S. Bankruptcy Code, which would trigger cross defaults under EME's guarantee of the lease obligations of Midwest Generation, as well as Midwest Generation's own obligations under the lease and under instruments governing the senior lease obligation bonds, and which could potentially give rise to counterparty rights and remedies under other documents.

Under the applicable accounting standards, Edison International would no longer consolidate EME for financial reporting purposes if it filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code, as Edison International would no longer have a controlling financial interest for accounting purposes. In order to deconsolidate EME for financial reporting purposes, the carrying values of the assets and liabilities of EME would be removed from Edison International's consolidated balance sheets as of the bankruptcy filing date and the investment in EME would be recorded at its estimated fair value. Any loss would be recognized in an amount equal to the excess of the book value of Edison International's investment in EME over the fair value of such investment. At September 30, 2012, the book value of Edison International's investment in EME was $1.24 billion. Any amounts recorded as part of accumulated other comprehensive loss related to EME would be recognized as a loss upon deconsolidation. At September 30, 2012, the amount recorded as accumulated other comprehensive loss related to EME was $128 million. In addition, Edison International would record any liabilities due to EME and certain liabilities that are joint and several with EME, including liabilities for uncertain tax positions taken in consolidated or combined tax returns of Edison International that are otherwise not resolved through the tax-allocation agreement and certain retirement plans. Under current regulations, during bankruptcy, EME would continue to be consolidated with Edison International for federal income tax purposes until a change in ownership occurred.

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Fair Value Measurements (Fair Value of Long-Term Debt Recorded at Carrying Value) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Fair Value of Long-Term Debt Recorded at Carrying Value
Long-term debt, including current portion, Carrying Value	$ 14,273	$ 13,746
Long-term debt, including current portion, Fair Value	$ 14,452	$ 14,264

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2012

Discontinued Operations and Disposal Groups [Abstract]

Summarized Financial Information for Discontinued Operations

The carrying amount of the major components of asset and liability of discontinued operations are as follows:

(in millions)	September 30, 2012			December 31, 2011
Cash and cash equivalents	$	55		$	79
Other current assets	114			128
Carrying value adjustment	(108		)	—
Total current assets	61			207
Other long-term assets	—			45
Assets of discontinued operations	61			252
Total current liabilities	61			27
Other long-term liabilities	—			9
Liabilities of discontinued operations	$	61		$	36

Summarized results of discontinued operations are as follows:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Total operating revenues	$	121		$	159		$	303		$	409
Total operating expenses	(138		)	(134		)	(385		)	(409		)
Asset impairment and other charges	(113		)	—			(134		)	—
Other income (expense)	5			2			7			(1		)
Income (loss) before income taxes	(125		)	27			(209		)	(1		)
Provision (benefit) for income taxes	(49		)	12			(80		)	2
Income (loss) from operations of discontinued operations	$	(76	)	$	15		$	(129	)	$	(3	)

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
ASSETS
Cash and cash equivalents	$ 1,080	$ 1,390
Receivables, less allowances of$75 for uncollectible accounts at both dates	1,167	908
Accrued unbilled revenue	787	519
Inventory	508	519
Prepaid taxes	36	88
Derivative assets	76	106
Restricted cash and cash equivalents	116	103
Margin and collateral deposits	88	58
Regulatory assets	250	494
Deferred income taxes	231	0
Other current assets	94	92
Assets of discontinued operations	61	207
Total current assets	4,494	4,484
Nuclear decommissioning trusts	3,997	3,592
Investments in unconsolidated affiliates	544	525
Other investments	189	211
Total investments	4,730	4,328
Utility property, plant and equipment, less accumulated depreciation of $7,378 and $6,894 at respective dates	29,314	27,569
Competitive power generation and other property, plant and equipment, less accumulated depreciation of $1,616 and $1,408 at respective dates	4,544	4,547
Total property, plant and equipment	33,858	32,116
Derivative assets	117	131
Restricted deposits	89	25
Rent payments in excess of levelized rent expense under plant operating leases	855	760
Regulatory assets	5,677	5,466
Other long-term assets	725	684
Total long-term assets	7,463	7,066
Assets of discontinued operations	0	45
Total assets	50,545	48,039
LIABILITIES AND EQUITY
Short-term debt	429	429
Current portion of long-term debt	565	57
Accounts payable	1,257	1,397
Accrued taxes	105	52
Accrued interest	207	205
Customer deposits	193	199
Derivative liabilities	109	268
Regulatory liabilities	493	670
Deferred income taxes	0	91
Other current liabilities	855	953
Liabilities of discontinued operations	61	27
Total current liabilities	4,274	4,348
Long-term debt	13,708	13,689
Deferred income taxes	5,745	5,396
Deferred investment tax credits	108	89
Customer advances	149	138
Derivative liabilities	717	547
Pensions and benefits	2,884	2,912
Asset retirement obligations	2,804	2,680
Regulatory liabilities	5,249	4,670
Other deferred credits and other long-term liabilities	2,887	2,475
Total deferred credits and other liabilities	20,543	18,907
Liabilities of discontinued operations	0	9
Total liabilities	38,525	36,953
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)	2,385	2,360
Accumulated other comprehensive loss	(168)	(139)
Retained earnings	7,806	7,834
Total Edison International's common shareholders' equity	10,023	10,055
Preferred and preference stock of utility	1,759	1,029
Other noncontrolling interests	238	2
Total noncontrolling interests	1,997	1,031
Total equity	12,020	11,086
Total liabilities and equity	$ 50,545	$ 48,039

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Variable Interest Entities

9 Months Ended

Sep. 30, 2012

Variable Interest Entities Disclosure [Abstract]

Variable Interest Entities

Variable Interest Entities

Categories of Variable Interest Entities

Projects or Entities that are Consolidated

At September 30, 2012 and December 31, 2011, 16 and 13 wind projects were consolidated with a total generating capacity of 861 MW and 570 MW, respectively, that have noncontrolling interests held by others. The increase from the projects consolidated after December 31, 2011 was due to the Capistrano Wind equity capital transaction discussed below. In determining that Edison International's subsidiary, EME, was the primary beneficiary of the projects that are consolidated, key factors considered were EME's ability to direct commercial and operating activities and EME's obligation to absorb losses of the variable interest entities.

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

(in millions)	September 30, 2012		December 31, 2011
Current assets	$	71	$	36
Net property, plant and equipment	1,090		675
Other long-term assets	73		5
Total assets	$	1,234	$	716
Current liabilities	$	40	$	28
Long-term debt net of current portion	172		57
Deferred revenues	172		69
Long-term derivative liabilities	23		—
Other long-term liabilities	38		22
Total liabilities	$	445	$	176
Noncontrolling interests	$	238	$	2

Assets serving as collateral for the debt obligations had a carrying value of $467 million and $136 million at September 30, 2012 and December 31, 2011, respectively, and primarily consist of property, plant and equipment.

Capistrano Wind Equity Capital

On February 13, 2012, Edison Mission Wind Inc. ("Edison Mission Wind") sold its indirect equity interests in the Cedro Hill wind project (150 MW in Texas), the Mountain Wind Power I project (61 MW in Wyoming) and the Mountain Wind Power II project (80 MW in Wyoming) to a new venture, Capistrano Wind Partners. Outside investors provided $238 million of the funding. Capistrano Wind Partners also agreed to acquire the Broken Bow I wind project (80 MW in Nebraska) and the Crofton Bluffs wind project (40 MW in Nebraska) for consideration expected to include $140 million from the same outside investors upon the satisfaction of specified conditions, including commencement of commercial operation and conversion of project debt financing to term loans. In March 2012, EME received a distribution of the proceeds from outside investors, which was used for general corporate purposes. Through their ownership of Capistrano Wind Holdings, an indirect subsidiary of EME, Edison Mission Wind, and EME's parent company, Mission Energy Holding Company ("MEHC"), own 100% of the Class A equity interests in Capistrano Wind Partners, and the Class B preferred equity interests are held by outside investors. Under the terms of the formation documents, preferred equity interests receive 100% of the cash available for distribution, up to a scheduled amount to target a certain return and thereafter cash distributions are shared. Cash available for distribution includes 90% of the tax benefits realized by MEHC and contributed to Capistrano Wind Partners.

Edison Mission Wind retains indirect beneficial ownership of the common equity in the projects, net of a $4 million preferred investment made by MEHC, a note receivable of $107 million from the sale of the project companies, and retains responsibilities for managing the operations of Capistrano Wind Holdings and its projects, and accordingly, EME will continue to consolidate these projects. The $238 million contributed by the third-party interests is reflected in "Other noncontrolling interests" on Edison International's consolidated balance sheets at September 30, 2012. This transaction was accounted for as a transfer among entities under common control and, therefore, resulted in no change in the book basis of the transferred assets. However, the transaction triggered a taxable gain and new tax basis in the assets with a corresponding adjustment to deferred taxes and a reduction to equity of $21 million.

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has 17 power purchase agreements ("PPAs") that have variable interests in VIEs, including 7 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 these 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 through demonstration of compliance with its CPUC-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 3,900 MW at September 30, 2012 and the amounts that SCE paid to these projects were $158 million and $178 million for the three months ended September 30, 2012 and 2011, respectively, and $292 million and $347 million for the nine months ended September 30, 2012 and 2011, respectively. These amounts are recoverable in customer rates, subject to reasonableness review.

Unconsolidated Trust

In May 2012, SCE Trust I issued $475 million (aggregate liquidation preference) of 5.625% trust securities (cumulative, liquidation amount of $25 per share) to the public and $10,000 of common stock (100%) to SCE. The trust invested the proceeds of these trust securities in Series F Preference Stock issued by SCE in the principal amount of $475 million (cumulative, $2,500 per share liquidation value) and which have substantially the same payment terms as the trust securities. The trust securities and the Series F Preference Stock do not have a maturity date. Upon any redemption of the Series F Preference Stock, a corresponding dollar amount of trust securities will be redeemed (for further information see Note 13). SCE Trust I will pay dividends at the same rate and on the same dates on the trust securities when, and if the SCE board of directors declare and make dividend payments on the Series F Preference Stock. The trust will use the dividends, if any, it receives on the Series F Preference Stock to make its corresponding dividend payments on the trust securities. If SCE does not make dividend payments to the trust, SCE would be prohibited from paying dividends on its common stock. SCE has fully and unconditionally guaranteed the payment of the trust securities and also its dividend payments, if and when, SCE pays dividends on the Series F Preference Stock.

SCE Trust I was formed for the exclusive purpose of issuing trust preference securities (“trust securities”). The trust is a VIE. SCE has concluded that it is not the primary beneficiary of this VIE as it does not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the trust. The trust's balance sheet as of September 30, 2012, consisted of an investment of $475 million in the Series F Preference Stock, $475 million of trust securities and $10,000 of common stock. The trust's income statement consisted of dividend income and accrued dividend payments of $7 million and $10 million for the three- and nine-months ended September 30, 2012, respectively.

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Accumulated Other Comprehensive Loss (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance, at the beginning of period			$ (139)
Current period change	(11)	(27)	(29)	(48)
Balance, at the end of period	(168)		(168)
Commodity Contracts
Increase (Decrease) in Accumulated Other Comprehensive Income
Unrealized derivative gains (losses) after taxes recorded in accumulated other comprehensive loss	7		7
Unrealized gains on cash flow hedges, net of tax, expected to be reclassified into earnings during the next 12 months			3
Interest Rate Contracts
Increase (Decrease) in Accumulated Other Comprehensive Income
Unrealized derivative gains (losses) after taxes recorded in accumulated other comprehensive loss	(79)		(79)
Unrealized Loss on Cash Flow Hedges
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance, at the beginning of period			(34)
Current period change			(38)
Balance, at the end of period	(72)		(72)
Pension and PBOP- Net Gain (Loss)
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance, at the beginning of period			(100)
Current period change			9
Balance, at the end of period	(91)		(91)
Pension and PBOP- Prior Service Cost
Increase (Decrease) in Accumulated Other Comprehensive Income
Balance, at the beginning of period			(5)
Current period change			0
Balance, at the end of period	$ (5)		$ (5)

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Business Segments

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Business Segments

Business Segments

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)	2012			2011			2012			2011
Operating Revenue:
Electric utility	$	3,731		$	3,386		$	8,794		$	8,063
Competitive power generation	340			437			1,009			1,277
Parent and other2	(1		)	(1		)	(3		)	(3		)
Consolidated Edison International	$	4,070		$	3,822		$	9,800		$	9,337
Net Income (Loss) attributable to Edison International:
Electric utility	$	363		$	406		$	736		$	838
Competitive power generation1	(137		)	33			(331		)	(17		)
Parent and other2	(36		)	(13		)	(48		)	(19		)
Consolidated Edison International	$	190		$	426		$	357		$	802

Segment balance sheet information was:

(in millions)	September 30, 2012			December 31, 2011
Total Assets:
Electric utility	$	43,059		$	40,315
Competitive power generation	7,934			8,392
Parent and other2	(448		)	(668		)
Consolidated Edison International	$	50,545		$	48,039

¹  Includes earnings (losses) from discontinued operations of $(76) million and $15 million for the three months ended September 30, 2012 and 2011, respectively, and $(129) million and $(3) million for the nine months ended September 30, 2012 and 2011, 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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Regulatory Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets Included on the Consolidated Balance Sheets

Regulatory assets included on the consolidated balance sheets are:

(in millions)	September 30, 2012		December 31, 2011
Current:
Regulatory balancing accounts	$	108	$	223
Energy derivatives	141		264
Other	1		7
Total Current	250		494
Long-term:
Deferred income taxes – net	2,148		2,020
Pensions and other postretirement benefits	1,657		1,703
Energy derivatives	573		487
Unamortized investments – net	484		484
Unamortized loss on reacquired debt	233		249
Nuclear-related investment – net	145		156
Regulatory balancing accounts	102		69
Other	335		298
Total Long-term	5,677		5,466
Total Regulatory Assets	$	5,927	$	5,960

Regulatory Liabilities Included on the Consolidated Balance Sheets

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	September 30, 2012		December 31, 2011
Current:
Regulatory balancing accounts	$	478	$	661
Other	15		9
Total Current	493		670
Long-term:
Costs of removal	2,745		2,697
Asset Retirement Obligations	1,378		1,105
Regulatory balancing accounts	1,119		864
Other	7		4
Total Long-term	5,249		4,670
Total Regulatory Liabilities	$	5,742	$	5,340

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Preferred and Preference Stock of Utility

9 Months Ended

Sep. 30, 2012

Preferred And Preference Stock Of Utility Disclosure [Abstract]

Preferred and Preference Stock of Utility

Preferred and Preference Stock of Utility

During the first quarter of 2012, SCE issued 350,000 shares of 6.25% Series E Preference Stock (cumulative, $1,000 liquidation value). The Series E preference shares may not be redeemed prior to February 1, 2022. After February 1, 2022, SCE may at its option, redeem the shares, in whole or in part for a price of $1,000 per share plus accrued and unpaid dividends, if any. The shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used to repay commercial paper borrowings and to fund SCE's capital program.

During the second quarter of 2012, SCE issued 190,004 shares of 5.625% Series F Preference Stock (cumulative, $2,500 liquidation value) to SCE Trust I, a special purpose entity formed to issue trust securities as discussed in Note 3. Variable Interest Entities. The Series F Preference Stock may not be redeemed prior to June 15, 2017. After June 15, 2017, SCE may at its option, redeem the shares, in whole or in part for a price of $2,500 per share plus accrued and unpaid dividends, if any. The shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used to repay commercial paper borrowings, for general corporate purposes and to redeem and retire $75 million of the Series A Preference Stock.