EDISON INTERNATIONAL - Quarter Report: 2012 March (Form 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 March 31, 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 April 30, 2012
Common Stock, no par value		325,811,206

TABLE OF CONTENTS



GLOSSARY			iii
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		10
	Note 3. Variable Interest Entities		11
	Note 4. Fair Value Measurements		12
	Note 5. Debt and Credit Agreements		18
	Note 6. Derivative Instruments and Hedging Activities		18
	Note 7. Income Taxes		24
	Note 8. Pension Plans and Postretirement Benefits Other Than Pensions		25
	Note 9. Commitments and Contingencies		26
	Note 10. Environmental Developments		32
	Note 11. Accumulated Other Comprehensive Loss		32
	Note 12. Supplemental Cash Flows Information		33
	Note 13. Preferred and Preference Stock of Utility		33
	Note 14. Regulatory Assets and Liabilities		33
	Note 15. Other Investments		34
	Note 16. Other Income and Expenses		35
	Note 17. Business Segments		36
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			37
FORWARD-LOOKING STATEMENTS			37
EDISON INTERNATIONAL OVERVIEW			39
	Highlights of Operating Results		39
	Management Overview of SCE		39
		2012 CPUC General Rate Case	39
		San Onofre Outage, Inspection and Repair Issues	40
		2013 Cost of Capital Application	40
		Capital Program	41
	Management Overview of EMG		41
		Midwest Generation Environmental Compliance Plans and Costs	41
		Homer City Lease	42
	Environmental Developments		43
SOUTHERN CALIFORNIA EDISON COMPANY			44
RESULTS OF OPERATIONS			44
	Utility Earning Activities		44
	Utility Cost-Recovery Activities		45
	Supplemental Operating Revenue Information		45
	Income Taxes		46
LIQUIDITY AND CAPITAL RESOURCES			46
	Available Liquidity		46



	Regulatory Proceedings	47
	Dividend Restrictions	47
	Margin and Collateral Deposits	47
	Workers Compensation Self-Insurance Fund	47
	Historical Segment Cash Flows	48
	Contractual Obligations and Contingencies	48
MARKET RISK EXPOSURES		49
	Commodity Price Risk	49
	Credit Risk	49
EDISON MISSION GROUP		50
RESULTS OF OPERATIONS		50
LIQUIDITY AND CAPITAL RESOURCES		56
	Available Liquidity	56
	Capital Investment Plan	57
	Historical Segment Cash Flows	58
	Credit Ratings	59
	Margin, Collateral Deposits and Other Credit Support for Energy Contracts	59
	Debt Covenants and Dividend Restrictions	60
	Contractual Obligations and Contingencies	60
	Off-Balance Sheet Transactions	60
	Environmental Matters and Regulations	61
MARKET RISK EXPOSURES		61
	Derivative Instruments	61
	Commodity Price Risk	61
	Credit Risk	65
	Interest Rate Risk	65
EDISON INTERNATIONAL PARENT AND OTHER		66
RESULTS OF OPERATIONS		66
LIQUIDITY AND CAPITAL RESOURCES		66
	Historical Segment Cash Flows	66
EDISON INTERNATIONAL (CONSOLIDATED)		68
LIQUIDITY AND CAPITAL RESOURCES		68
	Contractual Obligations	68
CRITICAL ACCOUNTING ESTIMATES AND POLICIES		68
NEW ACCOUNTING GUIDANCE		68
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		68
ITEM 4. CONTROLS AND PROCEDURES		68
	Disclosure Controls and Procedures	68
	Internal Control Over Financial Reporting	68
PART II. OTHER INFORMATION		69
ITEM 1. LEGAL PROCEEDINGS		69
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		69
ITEM 6. EXHIBITS		70
SIGNATURE		71

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

iii



Global Settlement		A settlement between Edison International and the IRS that resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002 and related matters with state tax authorities.
GRC		general rate case
GWh		gigawatt-hours
Homer City		EME Homer City Generation L.P., a Pennsylvania limited partnership that leases and operates three coal-fired electric generating units and related facilities located in Indiana County, Pennsylvania
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
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)

(This page has been left blank intentionally.)

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



Consolidated Statements of Income	Edison International

	Three months ended March 31,
(in millions, except per-share amounts, unaudited)	2012			2011
Electric utility	$	2,412		$	2,230
Competitive power generation	444			552
Total operating revenue	2,856			2,782
Fuel	283			258
Purchased power	615			508
Operation and maintenance	1,184			1,149
Depreciation, decommissioning and amortization	456			417
Asset impairments and other	14			—
Total operating expenses	2,552			2,332
Operating income	304			450
Interest and dividend income	3			4
Equity in loss from unconsolidated affiliates – net	(1		)	(5		)
Other income	31			41
Interest expense	(212		)	(196		)
Other expenses	(10		)	(13		)
Income from continuing operations before income taxes	115			281
Income tax expense	—			65
Income from continuing operations	115			216
Loss from discontinued operations, net of tax	(1		)	(2		)
Net income	114			214
Dividends on preferred and preference stock of utility	19			14
Other noncontrolling interests	2			—
Net income attributable to Edison International common shareholders	$	93		$	200
Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	$	94		$	202
Loss from discontinued operations, net of tax	(1		)	(2		)
Net income attributable to Edison International common shareholders	$	93		$	200
Basic earnings (loss) per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding	326			326
Continuing operations	$	0.28		$	0.62
Discontinued operations	—			(0.01		)
Total	$	0.28		$	0.61
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			328
Continuing operations	$	0.28		$	0.62
Discontinued operations	—			(0.01		)
Total	$	0.28		$	0.61
Dividends declared per common share	$	0.325		$	0.320

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



Consolidated Statements of Comprehensive Income	Edison International

	Three months ended March 31,
(in millions, unaudited)	2012			2011
Net income	$	114		$	214
Other comprehensive income (loss), net of tax:
Pension and postretirement benefits other than pensions:
Amortization of net loss included in net income, net of income tax expense of $4 and $1 for 2012 and 2011, respectively	7			3
Unrealized gain (loss) on derivatives qualified as cash flow hedges:
Unrealized holding gain arising during the period, net of income tax expense of $17 and $4 for 2012 and 2011, respectively	25			6
Reclassification adjustments included in net income, net of income tax benefit of $8 and $6 for 2012 and 2011, respectively	(11		)	(10		)
Other comprehensive income (loss)	21			(1		)
Comprehensive income	135			213
Less: Comprehensive income attributable to noncontrolling interests	21			14
Comprehensive income attributable to Edison International	$	114		$	199

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



Consolidated Balance Sheets	Edison International

(in millions, unaudited)	March 31, 2012		December 31, 2011
ASSETS
Cash and cash equivalents	$	1,483	$	1,469
Receivables, less allowances of $76 and $75 for uncollectible accounts at respective dates	753		908
Accrued unbilled revenue	508		519
Inventory	579		624
Prepaid taxes	121		88
Derivative assets	90		106
Restricted cash and cash equivalents	187		103
Margin and collateral deposits	96		58
Regulatory assets	692		494
Other current assets	206		115
Total current assets	4,715		4,484
Nuclear decommissioning trusts	3,853		3,592
Investments in unconsolidated affiliates	522		525
Other investments	221		211
Total investments	4,596		4,328
Utility property, plant and equipment, less accumulated depreciation of $7,088 and $6,894 at respective dates	28,133		27,569
Competitive power generation and other property, plant and equipment, less accumulated depreciation of $1,478 and $1,408 at respective dates	4,547		4,547
Total property, plant and equipment	32,680		32,116
Derivative assets	117		128
Restricted deposits	60		51
Rent payments in excess of levelized rent expense under plant operating leases	798		760
Regulatory assets	5,713		5,466
Other long-term assets	705		706
Total long-term assets	7,393		7,111





Total assets	$	49,384	$	48,039

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



Consolidated Balance Sheets	Edison International

(in millions, except share amounts, unaudited)	March 31, 2012			December 31, 2011
LIABILITIES AND EQUITY
Short-term debt	$	343		$	429
Current portion of long-term debt	61			57
Accounts payable	1,067			1,419
Accrued taxes	112			52
Accrued interest	229			205
Customer deposits	195			199
Derivative liabilities	255			268
Regulatory liabilities	645			670
Other current liabilities	768			1,049
Total current liabilities	3,675			4,348
Long-term debt	14,131			13,689
Deferred income taxes	5,686			5,396
Deferred investment tax credits	88			89
Customer advances	141			138
Derivative liabilities	803			547
Pensions and benefits	2,882			2,912
Asset retirement obligations	2,730			2,688
Regulatory liabilities	5,103			4,670
Other deferred credits and other long-term liabilities	2,538			2,476
Total deferred credits and other liabilities	19,971			18,916
Total liabilities	37,777			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)	2,325			2,360
Accumulated other comprehensive loss	(118		)	(139		)
Retained earnings	7,783			7,834
Total Edison International's common shareholders' equity	9,990			10,055
Preferred and preference stock of utility	1,374			1,029
Other noncontrolling interests	243			2
Total noncontrolling interests	1,617			1,031
Total equity	11,607			11,086
Total liabilities and equity	$	49,384		$	48,039

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



Consolidated Statements of Cash Flows	Edison International
	Three months ended March 31,
(in millions, unaudited)	2012			2011
Cash flows from operating activities:
Net income	$	114		$	214
Less: Loss from discontinued operations	(1		)	(2		)
Income from continuing operations	115			216
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	456			417
Regulatory impacts of net nuclear decommissioning trust earnings	77			41
Other amortization	26			37
Asset impairments and other	15			—
Stock-based compensation	8			7
Equity in loss from unconsolidated affiliates	1			5
Distributions from unconsolidated affiliates	—			5
Deferred income taxes and investment tax credits	(22		)	226
Income from leveraged leases	(1		)	(1		)
Proceeds from U.S. treasury grants	29			—
Changes in operating assets and liabilities:
Receivables	118			128
Inventory	44			(18		)
Margin and collateral deposits – net of collateral received	(36		)	15
Prepaid taxes	(33		)	(143		)
Other current assets	22			(6		)
Rent payments in excess of levelized rent expense	(38		)	(32		)
Accounts payable	(78		)	(49		)
Accrued taxes	322			1
Other current liabilities	(426		)	(207		)
Derivative assets and liabilities – net	295			106
Regulatory assets and liabilities – net	(254		)	(42		)
Other assets	(7		)	(7		)
Other liabilities	45			21
Operating cash flows from discontinued operations	(1		)	(2		)
Net cash provided by operating activities	677			718
Cash flows from financing activities:
Long-term debt issued	449			82
Long-term debt issuance costs	(8		)	(1		)
Long-term debt repaid	(9		)	(9		)
Preference stock issued – net	345			123
Short-term debt financing – net	(86		)	294
Settlements of stock-based compensation – net	(28		)	(7		)
Cash contributions from noncontrolling interests	238			—
Dividends and distributions to noncontrolling interests	(14		)	(13		)
Dividends paid	(106		)	(104		)
Net cash provided by financing activities	$	781		$	365

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



Consolidated Statements of Cash Flows	Edison International
	Three months ended March 31,
(in millions, unaudited)	2012			2011
Cash flows from investing activities:
Capital expenditures	$	(1,276	)	$	(1,133	)
Proceeds from sale of nuclear decommissioning trust investments	602			622
Purchases of nuclear decommissioning trust investments and other	(684		)	(669		)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment	1			5
Investments in other assets	(87		)	1
Net cash used by investing activities	(1,444		)	(1,174		)
Net increase (decrease) in cash and cash equivalents	14			(91		)
Cash and cash equivalents, beginning of period	1,469			1,389
Cash and cash equivalents, end of period	$	1,483		$	1,298

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

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 month period ended March 31, 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.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $1.2 billion and $1.3 billion at March 31, 2012 and December 31, 2011, respectively. Generally, the carrying value of cash equivalents equals the fair value, as these investments have maturities of three months or less.

Edison International temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. Edison International reclassified $178 million and $220 million of checks issued, but not yet paid by the financial institution, from cash to accounts payable at March 31, 2012 and December 31, 2011, respectively.

Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents at March 31, 2012 and December 31, 2011 included $97 million received from a wind financing that was held in escrow at those dates and is expected to be released in the second quarter of 2012 when the project achieves certain completion milestones. At March 31, 2012, restricted cash and cash equivalents also included $74 million to support outstanding letters of credit issued under EMG'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)	March 31, 2012		December 31, 2011
Coal, gas, fuel oil and other raw materials	$	170	$	211
Spare parts, materials and supplies	409		413
Total inventory	$	579	$	624

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 March 31,
(in millions)	2012		2011
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	94	$	202
Participating securities dividends	—		—
Income from continuing operations available to common shareholders	$	94	$	202
Weighted average common shares outstanding	326		326
Basic earnings per share – continuing operations	$	0.28	$	0.62
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	94	$	202
Income impact of assumed conversions	—		1
Income from continuing operations available to common shareholders and assumed conversions	$	94	$	203
Weighted average common shares outstanding	326		326
Incremental shares from assumed conversions	3		2
Adjusted weighted average shares – diluted	329		328
Diluted earnings per share – continuing operations	$	0.28	$	0.62

Stock-based compensation awards to purchase 8,602,107 and 8,980,322 shares of common stock were outstanding for the three months ended March 31, 2012 and 2011, respectively, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares and therefore, the effect would have been antidilutive.

New Accounting Guidance

Accounting Guidance Adopted in 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.

Note 2. Consolidated Statements of Changes in Equity

The following table provides the changes in equity for the three months ended March 31, 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	—			—			93			93			2		19			114
Other comprehensive income	—			21			—			21			—		—			21
Contributions from noncontrolling interests¹	—			—			—			—			238		—			238
Transfer of assets to Capistrano Wind Partners²	(50		)	—			—			(50		)	—		—			(50		)
Common stock dividends declared ($0.325 per share)	—			—			(106		)	(106		)	—		—			(106		)
Dividends, distributions to noncontrolling interests and other	—			—			—			—			1		(19		)	(18		)
Stock-based compensation and other	8			—			(36		)	(28		)	—		—			(28		)
Noncash stock-based compensation and other	7			—			(2		)	5			—		—			5
Issuance of preference stock	—			—			—			—			—		345			345
Balance at March 31, 2012	$	2,325		$	(118	)	$	7,783		$	9,990		$	243	$	1,374		$	11,607


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


²	Additional paid in capital was reduced $50 million related 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 three months ended March 31, 2011.



	Equity Attributable to Edison International											Noncontrolling Interests
(in millions)	Common Stock		Accumulated Other Comprehensive Loss			Retained Earnings			Subtotal			Other			Preferred and Preference Stock			Total Equity
Balance at December 31, 2010	$	2,331	$	(76	)	$	8,328		$	10,583		$	4		$	907		$	11,494
Net income	—		—			200			200			—			14			214
Other comprehensive loss	—		(1		)	—			(1		)	—			—			(1		)
Common stock dividends declared ($0.32 per share)	—		—			(104		)	(104		)	—			—			(104		)
Dividends, distributions to noncontrolling interests and other	—		—			—			—			(1		)	(14		)	(15		)
Stock-based compensation and other	2		—			(9		)	(7		)	—			—			(7		)
Noncash stock-based compensation and other	7		—			(2		)	5			—			—			5
Issuance of preference stock	—		—			—			—			—			123			123
Balance at March 31, 2011	$	2,340	$	(77	)	$	8,413		$	10,676		$	3		$	1,030		$	11,709

Note 3. Variable Interest Entities

Categories of Variable Interest Entities

Projects or Entities that are Consolidated

At March 31, 2012 and December 31, 2011, EMG consolidated 16 and 13 projects, respectively, with a total generating capacity of 861 MW and 570 MW, respectively, that have noncontrolling interests held by others. Projects consolidated at March 31, 2012 increased from the projects consolidated at December 31, 2011, due to the Capistrano Wind equity capital transaction as discussed below. In determining that EMG was the primary beneficiary of the projects that are consolidated, key factors considered were EMG's ability to direct commercial and operating activities and EMG'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)	March 31, 2012		December 31, 2011
Current assets	$	87	$	36
Net property, plant and equipment	1,194		675
Other long-term assets	18		5
Total assets	$	1,299	$	716
Current liabilities	$	32	$	28
Long-term debt net of current portion	179		57
Deferred revenues	174		69
Other long-term liabilities	56		22
Total liabilities	$	441	$	176
Noncontrolling interests	$	242	$	2

Assets serving as collateral for the debt obligations had a carrying value of $474 million and $136 million at March 31, 2012 and December 31, 2011, respectively, and primarily consist of property, plant and equipment.

Capistrano Wind Equity Capital

As part of its plan to obtain third-party equity capital to finance the development of a portion of EMG's wind portfolio, on February 13, 2012, 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. In March 2012, EME received a distribution of the proceeds from outside investors, which will be 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 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, and retains responsibilities for managing the operations of Capistrano Wind Holdings and its projects, and accordingly, EMG 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 March 31, 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 did trigger a taxable gain and new tax basis in the assets with a corresponding adjustment to deferred taxes and a reduction to equity of $50 million.

EMG's share in the earnings or losses of the Capistrano Wind entities is calculated under the hypothetical liquidation book value ("HLBV") method due to complex preferences in distribution provisions. The income from the Cedro Hill, Mountain Wind Power I and Mountain Wind Power II wind projects attributable to noncontrolling interests was $2 million for the first quarter of 2012.

Variable Interest in VIEs that are not Consolidated

SCE has 16 power purchase agreements ("PPAs") that have variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to fuel the plants and 10 contracts with qualifying facilities ("QFs") that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. In general, because payments for capacity are the primary source of income, the most significant economic activity for 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 3,820 MW at March 31, 2012 and the amounts that SCE paid to these projects were $78 million and $86 million for the three months ended March 31, 2012 and 2011, respectively. These amounts are recoverable in customer rates, subject to reasonableness review.

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 March 31, 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:



	March 31, 2012
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral¹			Total
Assets at Fair Value
Money market funds²	$	1,222	$	—	$	—		$	—		$	1,222
Derivative contracts:
Electricity	—		144		143			(93		)	194
Natural gas	6		4		—			(10		)	—
Fuel oil	7		—		—			(7		)	—
Tolling	—		—		13			—			13
Subtotal of derivative contracts	13		148		156			(110		)	207
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks³	2,124		—		—			—			2,124
Municipal bonds	—		696		—			—			696
U.S. government and agency securities	481		161		—			—			642
Corporate bonds⁴	—		369		—			—			369
Short-term investments, primarily cash equivalents⁵	2		34		—			—			36
Subtotal of nuclear decommissioning trusts	2,607		1,260		—			—			3,867
Total assets⁶	3,850		1,408		156			(110		)	5,304
Liabilities at Fair Value
Derivative contracts:
Electricity	—		13		99			(28		)	84
Natural gas	—		258		48			(81		)	225
Tolling	—		—		671			—			671
Subtotal of derivative contracts	—		271		818			(109		)	980
Interest rate contracts	—		78		—			—			78
Total liabilities	—		349		818			(109		)	1,058
Net assets (liabilities)	$	3,850	$	1,059	$	(662	)	$	(1	)	$	4,246



	December 31, 2011
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral¹			Total
Assets at Fair Value
Money market funds²	$	1,321	$	—	$	—		$	—		$	1,321
Derivative contracts:
Electricity	—		66		218			(62		)	222
Natural gas	4		5		—			(7		)	2
Fuel oil	4		—		—			(4		)	—
Tolling	—		—		10			—			10
Subtotal of commodity contracts	8		71		228			(73		)	234
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	3,669		1,306		228			(73		)	5,130
Liabilities at Fair Value
Derivative contracts:
Electricity	—		13		77			(21		)	69
Natural gas	—		234		23			(52		)	205
Tolling	—		—		451			—			451
Subtotal of commodity contracts	—		247		551			(73		)	725
Interest rate contracts	—		90		—			—			90
Total liabilities	—		337		551			(73		)	815
Net assets (liabilities)	$	3,669	$	969	$	(323	)	$	—		$	4,315


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 69% and 70% of the equity investments were located in the United States at March 31, 2012 and December 31, 2011, respectively.


⁴	At March 31, 2012 and December 31, 2011, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $38 million and $22 million, respectively.


⁵	Excludes net payables of $14 million and net receivables of $25 million at March 31, 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 $30 million and $31 million at March 31, 2012 and December 31, 2011, respectively, of cash surrender value of life insurance investments for deferred compensation.

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



	March 31,
(in millions)	2012				2011
Fair value of net assets (liabilities) at beginning of period	$	(323	)		$	97
Total realized/unrealized gains (losses):
Included in earnings¹	(15		)		—
Included in regulatory assets and liabilities²	(293		)	³	(134		)
Included in accumulated other comprehensive income⁴	2				1
Purchases	27				5
Settlements	(9		)		(11		)
Transfers out of Level 3⁵	(51		)		(2		)
Fair value of net liabilities at end of period	$	(662	)		$	(44	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period⁶	$	(295	)		$	(139	)


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 were $(7) million and $(6) million for the years ended March 31, 2012 and 2011, respectively. 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 three months ended March 31, 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 the risk department which reports to the chief financial officer. This department obtains 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 key 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:



March 31, 2012				Quantitative Information About Level 3 Fair Value Measurements
	Fair Value (in millions)								Range
	Assets			Liabilities			Valuation Technique(s)	Unobservable Input	(Weighted Average)
Electricity:
Options	$	12		$	86		Option model	Volatility of gas prices	25% – 48% (38%)
								Volatility of power prices	29% – 60% (43%)
								Power prices	$24.50 – $52.30 ($35.40)
Forwards	37			56			Discounted cash flow	Power prices	$2.10 – $54.00 ($30.96)
Congestion contracts	101			—			Market simulation model	Load forecast	7,645 MW – 26,334 MW
								Power prices	$(46.19) – $240.30
								Gas prices	$3.79 – $9.32
Congestion contracts	49			13			Discounted cash flow	Congestion prices	$(8.20) – $10.32 ($0.21)
Gas options	—			48			Option model	Volatility of gas prices	26% – 48% (41%)
Tolling	13			671			Option model	Volatility of gas prices	18% – 48% (23%)
								Volatility of power prices	26% – 60% (30%)
								Power prices	$20.00 – $89.50 ($53.40)
Netting	(56		)	(56		)
Total derivative contracts	$	156		$	818

Level 3 Fair Value Sensitivity

Gas Options, Power 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, an increase (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:



	March 31, 2012				December 31, 2011
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current portion	$	14,192	$	14,194	$	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, payables and short-term debt approximates fair value.

Note 5. Debt and Credit Agreements

Project Financings

Effective March 2012, EME completed through subsidiaries 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 March 31, 2012, no amounts were outstanding under the construction loans and letters of credit facilities.

In December 2011, EME completed, through its subsidiary, Tapestry Wind, LLC, 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 million 10-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 requesting that the Commission order the project to shut down at night due to alleged noise emissions. The release of the loan proceeds in escrow is subject to resolution of the complaint or further due diligence from the lenders. EME expects the loan proceeds to be released in the second quarter of 2012.

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

At March 31, 2012, SCE's outstanding commercial paper was $330 million at a weighted-average interest rate of 0.40%. This commercial paper was supported by a $2.3 billion credit facility. At December 31, 2011, the outstanding short-term debt was $419 million at a weighted-average interest rate of 0.44%. At March 31, 2012, letters of credit issued under SCE's credit facilities aggregated $63 million and are scheduled to expire in twelve months or less.

In February 2012, EME terminated its $564 million revolving credit facility and entered into $55 million bridge letter of credit facilities which expire June 8, 2012 and which are secured by cash collateral of at least equal to the issued amount. In the first quarter of 2012, EME also 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.

At March 31, 2012, Edison International (Parent)'s outstanding short-term debt was $13 million at a weighted-average interest rate of 0.87%. This short-term debt was supported by a $1.4 billion credit facility. At December 31, 2011, the outstanding short-term debt was $10 million at a weighted-average interest rate of 0.66%.

Letters of Credit

Letters of credit under EME's and its subsidiaries' credit facilities aggregated $179 million and were scheduled to expire as follows: $122 million in 2012, $29 million in 2013, $10 million in 2017 and $18 million in 2018. Standby letters of credit include $40 million issued in connection with the power purchase agreement with Southern California Edison, an affiliate of EME, under the Walnut Creek credit facility. Certain letters of credit are subject to automatic annual renewal provisions. At March 31, 2012, EME had $71 million in letters of credit which were supported by $74 million of cash collateral.

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	March 31, 2012	December 31, 2011
Electricity options, swaps and forwards	GWh	28,611	30,881
Natural gas options, swaps and forwards	Bcf	258	300
Congestion revenue rights	GWh	150,896	166,163
Tolling arrangements	GWh	103,491	104,154

Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at March 31, 2012:



	Derivative Assets									Derivative Liabilities¹
(in millions)	Short-Term			Long-Term			Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	65		$	72		$	137		$	338		$	1,153		$	1,491		$	1,354
Netting and collateral	(14		)	(7		)	(21		)	(84		)	(18		)	(102		)	(81		)
Total	$	51		$	65		$	116		$	254		$	1,135		$	1,389		$	1,273


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 are not reflected in 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 are also not reflected in earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.

The following table summarizes the components of economic hedging activity:



	Three months ended March 31,
(in millions)	2012			2011
Realized losses	$	(55	)	$	(39	)
Unrealized losses	(361		)	(96		)

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 $285 million and $216 million as of March 31, 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 March 31, 2012, SCE would be required to post $67 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 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 EMG does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements.

Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not designated as cash flow hedges. Economic hedges are accounted for at fair value on EMG's consolidated balance sheets 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 EMG's 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 EMG's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EMG presents its derivative assets and liabilities on a net basis on its consolidated balance sheets.

Notional Volumes of Derivative Instruments

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



March 31, 2012
				Hedging Activities
Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges		Economic Hedges		Trading Activities
Electricity	Forwards/Futures	Sales, net	GWh	5,850	1	102	3	—
Electricity	Forwards/Futures	Purchases, net	GWh	—		—		2,425
Electricity	Capacity	Sales, net	MW-Day (in thousands)	58	2	—		—
Electricity	Capacity	Purchases, net	MW-Day (in thousands)	—		—		161	2
Electricity	Congestion	Purchases, net	GWh	—		1,079	4	165,365	4
Natural gas	Forwards/Futures	Purchases, net	bcf	—		—		12.0
Fuel oil	Forwards/Futures	Purchases, net	barrels	—		360,000		—

At March 31, 2012, EMG had interest rate contracts with notional values totaling $681 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 March 31, 2012, EME had forward starting interest rate contracts with notional values totaling $502 million that will convert floating rate LIBOR-based debt to fixed rates ranging from 3.5429% to 4.0025%. These contracts have effective dates beginning June 2013 through December 2021 and expire May 2023 through December 2029.

In April 2012 pursuant to the agreements for financing of its interests in the Broken Bow and Crofton Bluffs wind projects, EME's subsidiaries entered into forward starting interest rate swap agreements with notional value totaling $139 million that converted floating rate LIBOR based debt to fixed rates ranging from 0.7825% to 2.96%. These contracts have effective dates beginning December 2012 through December 2013 and expire December 2013 through December 2027.



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	1	425	3	—
Electricity	Forwards/Futures	Purchases, net	GWh	—		—		2,926
Electricity	Capacity	Sales, net	MW-Day (in thousands)	89	2	—		—
Electricity	Capacity	Purchases, net	MW-Day (in thousands)	—		—		184	2
Electricity	Congestion	Purchases, net	GWh	—		2,528	4	230,798	4
Natural gas	Forwards/Futures	Sales, net	bcf	—		—		0.2
Fuel oil	Forwards/Futures	Purchases, net	barrels	—		240,000		—


¹	EMG's hedge products include forward and futures contracts that qualify for hedge accounting.


²	EMG'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	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.


⁴	Congestion contracts include financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.

At December 31, 2011, EMG 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, EMG 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 EMG's consolidated balance sheets:



March 31, 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	$	51		$	2		$	53		$	1		$	3		$	4		$	49
Interest rate contracts	—			—			—			—			78			78			(78		)
Economic hedges	57			3			60			47			2			49			11
Trading activities	408			180			588			360			117			477			111
	516			185			701			408			200			608			93
Netting and collateral received¹	(477		)	(133		)	(610		)	(407		)	(121		)	(528		)	(82		)
Total	$	39		$	52		$	91		$	1		$	79		$	80		$	11



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	$	41		$	1		$	42		$	2		$	3		$	5		$	37
Interest rate contracts	—			—			—			—			90			90			(90		)
Economic hedges	31			1			32			26			1			27			5
Trading activities	276			142			418			232			79			311			107
	348			144			492			260			173			433			59
Netting and collateral received¹	(308		)	(85		)	(393		)	(259		)	(83		)	(342		)	(51		)
Total	$	40		$	59		$	99		$	1		$	90		$	91		$	8


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
	Three Months Ended March 31,
	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	30			12			8			2
Reclassification to earnings	(19		)	—			(16		)	—			Competitive power generation revenue
End of period derivative gains (losses)	$	46		$	(78	)	$	35		$	(14	)


¹	Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive loss at March 31, 2012 and 2011 for commodity and interest rate contracts were $27 million and $(47) million, and $21 million and $(9) million, respectively.

For additional information, see Note 11.

EMG recorded net gains of $1 million and $2 million during the first quarters of 2012 and 2011, respectively, in operating revenues on the consolidated statements of operations representing the amount of cash flow hedge ineffectiveness.

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



		Three Months Ended March 31,
(in millions)	Income Statement Location	2012		2011
Economic hedges	Competitive power generation revenue	$	11	$	6
	Fuel	5		6
Trading activities	Competitive power generation revenue	20		16

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)	March 31, 2012		December 31, 2011
Collateral provided to counterparties:
Offset against derivative liabilities	$	83	$	53
Reflected in margin and collateral deposits	96		58
Collateral received from counterparties:
Offset against derivative assets	84		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 March 31,
(in millions)	2012			2011
Income from continuing operations before income taxes	$	115		$	281
Provision for income tax at federal statutory rate of 35%	40			98
Increase (decrease) in income tax from:
State tax benefit – net of federal tax expense	(9		)	—
Production and housing credits	(19		)	(18		)
Property-related	(10		)	(11		)
Other	(2		)	(4		)
Total income tax expense from continuing operations	$	—		$	65
Effective tax rate	*			23		%


^*	Not meaningful

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.

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 EMG's international assets, which if sustained, would result in a federal tax payment of approximately $194 million, including interest and penalties through March 31, 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 $94 million, including interest through March 31, 2012.

Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011. Federal income taxes of Edison International and its consolidated subsidiaries are generally the joint and several liabilities of members of the group under applicable tax laws and are paid by Edison International as the group's consolidated taxpayer, subject to internal tax-allocation agreements.

Tax Election at Homer City

On March 15, 2012, Homer City LP filed an election with the Internal Revenue Service to be treated as a partnership for federal and state income tax purposes effective for tax year 2011. As a result of this election, Homer City LP was treated for income tax purposes as though it had distributed all of its assets and liabilities to its partners, both of which are wholly-owned subsidiaries of EME. This distribution triggered a tax deduction of approximately $1.0 billion, which will be included on Edison International's 2011 federal and state income 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 $1.2 billion as of March 31, 2012.

Note 8. Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

Edison International made contributions of $7 million during the three months ended March 31, 2012 and expects to make $279 million of additional contributions during the remainder of 2012. In 2012, annual contributions made to most of the pension plans for SCE employees are anticipated to be recovered through CPUC-approved regulatory mechanisms, pending outcome of the 2012 GRC decision. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.

Expense components are:



	Three months ended March 31,
(in millions)	2012			2011
Service cost	$	43		$	43
Interest cost	49			52
Expected return on plan assets	(59		)	(60		)
Amortization of prior service cost	1			2
Amortization of net loss	18			6
Expense under accounting standards	52			43
Regulatory adjustment (deferred)	25			(6		)
Total expense recognized	$	77		$	37

Postretirement Benefits Other Than Pensions

Edison International made contributions of $6 million during the three months ended March 31, 2012 and expects to make $59 million of additional contributions during the remainder of 2012. In 2012, annual contributions made to plans for SCE employees are anticipated to be recovered through CPUC-approved regulatory mechanisms, pending outcome of the 2012 GRC decision. 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 March 31,
(in millions)	2012			2011
Service cost	$	13		$	11
Interest cost	30			33
Expected return on plan assets	(27		)	(28		)
Amortization of prior service credit	(9		)	(9		)
Amortization of net loss	12			9
Total expense	$	19		$	16

Note 9. Commitments and Contingencies

Power Plant and Other Lease Commitments

Homer City Lease and Environmental Project

Homer City made the required April 1, 2012 senior rent payment but did not make the April 1, 2012 payment of equity rent. On March 30, 2012, Homer City 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. For further discussion of the Homer City lease, refer to "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Power Plant and Other Lease Commitments—Sale-Leaseback Transactions" in the 2011 Form 10-K.

On March 29, 2012, Homer City and General Electric Capital Corporation ("GECC") entered into an Implementation Agreement (the Agreement) with respect to the Homer City plant. As addressed by the Agreement, an affiliate of the GECC-controlled owner-lessors of the Homer City plant has entered into an engineering, procurement and construction agreement and is in the process of executing related agreements for the construction of environmental improvements. GECC will have discretion over all decisions related to such agreements. Homer City agreed to conduct its business as set forth in the Agreement and to use commercially reasonable efforts to provide assistance to GECC and its affiliates in connection with the construction agreements. The Agreement also requires Homer City, at the request of GECC, to enter into one or more implementation transactions, as defined in the Agreement, for the divestiture of its leasehold interest in the Homer City plant (and, under certain circumstances, related assets and liabilities as specified) and to assist GECC in obtaining certain third-party consents or waivers. Homer City and GECC also agreed to enter into a transition services agreement in connection with any implementation transaction. There is no assurance that Homer City and GECC will actually consummate a divestiture transaction as contemplated by the Agreement.

The Agreement also contains certain indemnities by each party in favor of the other. The Agreement may be terminated by GECC in its sole discretion at any time effective immediately upon delivery of notice to Homer City. Homer City may terminate the Agreement in connection with certain terminations of the construction agreements, subject to certain conditions.

The estimated cost of installing sulfur dioxide ("SO₂") and particulate emissions control equipment for Units 1 and 2 of the Homer City plant is expected to be approximately $700 million to $750 million. On April 2, 2012, Homer City received the permit to construct such improvements from the Pennsylvania Department of Environmental Protection ("PADEP").

Included in the consolidated balance sheet at March 31, 2012 are assets and liabilities of Homer City. In the event that Homer City completes a divestiture transaction with its owner-lessors or EME ceases to control Homer City, EME will record a loss on disposition and classify Homer City as a discontinued operation. At March 31, 2012, Homer City assets of $209 million were composed of cash, inventory, and other assets and liabilities of $84 million were composed of accounts payable, accrued

liabilities and other liabilities. In addition, EMMT had an intercompany account receivable from Homer City of $13 million at March 31, 2012. Any loss on disposition will be determined based on the assets and liabilities as of the date of disposition, the terms and conditions of the relevant transaction and an assessment as to whether any ongoing contingencies exist.

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." Except as discussed below, EME has not recorded a liability related to these environmental indemnities.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of Midwest Generation's reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2013. There were approximately 245 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at March 31, 2012. Midwest Generation had recorded a liability of $54 million at March 31, 2012 related to this contractual indemnity.

Indemnities Related to the Homer City Plant

In connection with the acquisition of the Homer City plant, Homer City agreed to indemnify the sellers with respect to specified environmental liabilities before and after the date of sale. EME guaranteed this obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City plant, Homer City agreed to indemnify the 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." Also, in connection with the Implementation Agreement discussed above, Homer City has agreed to enter into one or more implementation transactions, at the request of GECC, on the terms outlined in the Implementation Agreement, which include indemnification for specified matters.

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 March 31, 2012, EME had recorded a liability of $34 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 obligation 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.

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

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, individually and in the aggregate, will not materially affect its results of operations or liquidity.

Midwest Generation New Source Review and Other Litigation

In August 2009, the United States Environmental Protection Agency ("US EPA") and the State of Illinois filed a complaint in the Northern District of Illinois alleging that Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration (PSD) requirements and of the New Source Performance Standards of the Clean Air Act (CAA), including alleged requirements to obtain a construction permit and to install controls sufficient to meet best available control technology (BACT) emission rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint 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. In March 2012, Midwest Generation filed motions to dismiss the cases, which are pending.

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.

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 Order Instituting Investigation ("OII") regarding this matter and SCE is found to have violated any CPUC rules, it could face penalties. In addition, the cost of any large scale review of poles or other equipment for safety compliance could be significant. 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.

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.

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 and is expected to close in late 2012. Under the agreement SCE would remain responsible for its pro rata share of certain environmental liabilities, including penalties arising from environmental violations prior to the sale, but SCE would not be liable for any costs of installing BACT or other costs related to continuing or extending Four Corners operations. SCE is unable to estimate a possible loss or range of loss associated with this matter.

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

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 March 31, 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 EMG (2 sites related to Midwest Generation) was $51 million, of which $43 million was related to SCE, including $12 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 $46 million total environmental remediation liability for SCE, $43 million has been recorded as a regulatory asset. SCE expects to recover $27 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 $16 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 $214 million and $5 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 its identified sites over a period of up to 30 years. Remediation costs in each of the next five years are expected to range from $7 million to $17 million. Costs incurred for the three months ended March 31, 2012 and 2011 were $2 million and $4 million, respectively.

Based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to estimates.

Nuclear Insurance

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

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

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and 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 insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $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 1, 2011, SCE's parent, Edison International, renewed its insurance coverage, which included coverage for SCE's wildfire liabilities up to a $575 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 1, 2011 to August 31, 2012). 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.

Note 10. Environmental Developments

Hazardous Air Pollutant Regulations

In December 2011, the US EPA announced the Mercury and Air Toxics Standards ("MATS") 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.

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 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.

Note 11. Accumulated Other Comprehensive Loss

Edison International's accumulated other comprehensive loss consists of:



(in millions)	Unrealized Gain (Loss) on Cash Flow Hedges			Pension and PBOP – Net Loss			Pension and PBOP – Prior Service Cost			Accumulated Other Comprehensive Loss
Balance at December 31, 2011	$	(34	)	$	(100	)	$	(5	)	$	(139	)
Change for 2012	14			7			—			21
Balance at March 31, 2012	$	(20	)	$	(93	)	$	(5	)	$	(118	)

Included in accumulated other comprehensive loss at March 31, 2012 was $27 million, net of tax, of unrealized gains on commodity-based cash flow hedges, and $47 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 May 31, 2014.

Unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. Approximately $28 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:



	Three months ended March 31,
(in millions)	2012			2011
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	157		$	155
Tax payments (refunds) – net	(3		)	(45		)
Dividends declared but not paid:
Common stock	$	106		$	104
Preferred and preference stock	10			10

Accrued capital expenditures at March 31, 2012 and 2011 were $419 million and $461 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.

Note 14. Regulatory Assets and Liabilities

Regulatory Assets

Regulatory assets included on the consolidated balance sheets are:



	March 31,		December 31,
(in millions)	2012		2011
Current:
Regulatory balancing accounts	$	362	$	223
Energy derivatives	320		264
Other	10		7
Total Current	692		494
Long-term:
Deferred income taxes – net	2,056		2,020
Pensions and other postretirement benefits	1,688		1,703
Energy derivatives	728		487
Unamortized investment – net	497		484
Unamortized loss on reacquired debt	244		249
Nuclear-related investment – net	152		156
Regulatory balancing accounts	84		69
Other	264		298
Total Long-term	5,713		5,466
Total Regulatory Assets	$	6,405	$	5,960

Regulatory Liabilities

Regulatory liabilities included on the consolidated balance sheets are:



	March 31,		December 31,
(in millions)	2012		2011
Current:
Regulatory balancing accounts	$	637	$	661
Other	8		9
Total Current	645		670
Long-term:
Costs of removal	2,736		2,697
Asset Retirement Obligations	1,322		1,105
Regulatory balancing accounts	1,039		864
Other	6		4
Total Long-term	5,103		4,670
Total Regulatory Liabilities	$	5,748	$	5,340

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	March 31, 2012		December 31, 2011		March 31, 2012		December 31, 2011
Stocks	—	$	885	$	865	$	2,124	$	1,899
Municipal bonds	2051	574		625		696		756
U.S. government and agency securities	2041	596		516		642		580
Corporate bonds	2054	305		259		369		317
Short-term investments and receivables/payables	One-year	21		38		22		40
Total		$	2,381	$	2,303	$	3,853	$	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 $602 million and $622 million for the three months ended March 31, 2012 and 2011, respectively. Unrealized holding gains, net of losses, were $1.5 billion and $1.3 billion at March 31, 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 March 31,
(in millions)	2012			2011
Balance at beginning of period	$	3,592		$	3,480
Gross realized gains	25			23
Gross realized losses	(4		)	—
Unrealized gains (losses) – net	184			102
Other-than-temporary impairments	(5		)	(9		)
Interest, dividends, contributions and other	61			23
Balance at end of period	$	3,853		$	3,619

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

Note 16. Other Income and Expenses

Other income and expenses are as follows:



	Three months ended March 31,
(in millions)	2012		2011
Other income:
Equity allowance for funds used during construction	$	20	$	29
Increase in cash surrender value of life insurance policies	7		7
Other	4		2
Total utility other income	31		38
Competitive power generation and other income	—		3
Total other income	$	31	$	41
Other expenses:
Civic, political and related activities and donations	$	6	$	7
Other	3		6
Total utility other expenses	9		13
Competitive power generation and other expenses	1		—
Total other expenses	$	10	$	13

Note 17. Business Segments

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



	Three months ended March 31,
(in millions)	2012			2011
Operating Revenue:
Electric utility	$	2,412		$	2,232
Competitive power generation	444			552
Parent and other²	—			(2		)
Consolidated Edison International	$	2,856		$	2,782
Net Income (Loss) attributable to Edison International:
Electric utility	$	182		$	222
Competitive power generation¹	(84		)	(20		)
Parent and other²	(5		)	(2		)
Consolidated Edison International	$	93		$	200

Segment balance sheet information was:



(in millions)	March 31, 2012			December 31, 2011
Total Assets:
Electric utility	$	41,605		$	40,315
Competitive power generation	8,472			8,392
Parent and other²	(693		)	(668		)
Consolidated Edison International	$	49,384		$	48,039


¹	Includes losses from discontinued operations of $(1) million and $(2) million for the three months ended March 31, 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.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Edison International's current expectations and projections about future events based on Edison International's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by Edison International that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact Edison International, include, but are not limited to:


•	cost of capital and the ability of Edison International or its subsidiaries to borrow funds and access the capital markets on reasonable terms;


•	environmental laws and regulations, at both state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business, including compliance with CPS (at Midwest Generation) and CAIR or CSAPR (as applicable) and the MATS rule at Midwest Generation and Homer City;


•	ability of SCE to recover its costs in a timely manner from its customers through regulated rates;


•	decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays in regulatory actions;


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


•	risks associated with the operation of transmission and distribution assets and nuclear and other power generating facilities including: nuclear fuel storage issues, public safety issues, failure, availability, efficiency, output, cost of repairs and retrofits of equipment and availability and cost of spare parts;


•	ability of EMG to meet its liquidity requirements and stabilize its capital structure during periods of operating losses;


•	the completion of the transactions for the divestiture of Homer City's leasehold interest and related assets and liabilities pursuant to the terms of the Implementation Agreement 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 in the event of nuclear or 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;


•	availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;


•	cost and availability of labor, equipment and materials;


•	ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance;


•	ability to recover uninsured losses in connection with wildfire-related liability;


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


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


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


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


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


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

•

risks inherent in the 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 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 months ended March 31, 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 months ended March 31, 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.

EDISON INTERNATIONAL OVERVIEW

Highlights of Operating Results



	Three months ended March 31,
(in millions)	2012			2011			Change
Net Income (Loss) attributable to Edison International
SCE	$	182		$	222		$	(40	)
EMG	(84		)	(20		)	(64		)
Edison International Parent and Other	(5		)	(2		)	(3		)
Edison International Consolidated	93			200			(107		)
Less: Non-Core Items
EMG Homer City	(23		)	(10		)	(13		)
EMG discontinued operations	(1		)	(2		)	1
Total non-core items	(24		)	(12		)	(12		)
Core Earnings (Losses)
SCE	182			222			(40		)
EMG	(60		)	(8		)	(52		)
Edison International Parent and Other	(5		)	(2		)	(3		)
Edison International Consolidated	$	117		$	212		$	(95	)

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 first quarter of 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 $40 million 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. The revenue requirement ultimately adopted by the CPUC will be retroactive to January 1, 2012. The variance also reflects a lower capitalization rate on funds used during construction. SCE has incurred $20 million of incremental steam generator inspection and repair costs related to outages at San Onofre which were offset by other operation and maintenance cost reductions.

EMG's 2012 core losses increased $52 million due to lower average realized energy and capacity prices and lower generation at the Midwest Generation plant and higher interest expense related to new energy project financings.

Consolidated non-core items for 2012 and 2011 for Edison International include the results for Homer City in anticipation of the orderly transfer of the Homer City plant to the owner-lessors, which will result in EMG's loss of substantially all beneficial economic interest in and material control of the Homer City plant.

Management Overview of SCE

2012 CPUC General Rate Case

As discussed in the year-ended 2011 MD&A, SCE filed its 2012 GRC application in November 2010. In October 2011, SCE submitted updated testimony, which changed SCE's requested 2012 base rate revenue requirement to $6.3 billion. The Division of Ratepayer Advocates, The Utility Reform Network and other intervenors recommended substantially less than the

amount requested by SCE. Intervenors have also recommended changes to SCE's proposed post-test year ratemaking methodology to be used for 2013 and 2014 as well as limiting the recovery amount of SCE's pension costs. A decision on the GRC is expected in the second quarter of 2012. SCE is currently recognizing revenue largely based on the 2011 authorized revenue requirement, however, 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.

San Onofre Outage, Inspection and Repair Issues

As discussed in the 2011 Form 10-K, in the first quarter of 2012, isolated areas of wear in some of the heat transfer tubes in San Onofre's Unit 2 steam generators were found during a planned outage and a water leak was detected in one of the tubes in a Unit 3 steam generator. Unit 3 was safely taken offline and both Units remain offline for ongoing, extensive inspections, testing and analysis.

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. Causal analysis of the tube to tube contact continues. The same area was re-inspected in the Unit 2 steam generators using a more sensitive inspection method and similar tube-to-tube wear was found on two tubes in one of the steam generators at wear levels below the detection capability of the initial testing. Earlier tests performed on the Unit 2 steam generators during the planned outage additionally found high levels of wear in some tubes that were in contact with a tube support structure. As a result, all tubes in contact with the support structure in both Unit 2 steam generators were preventively removed from service through plugging. Subsequent inspections on Unit 3 found similar tube-to-support structure wear, and the affected tubes will also be plugged preventively.

During the inspection and testing of the 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 and the NRC was notified as required. Given these test results, the NRC launched an Augmented Inspection Team 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. The efforts of the Augmented Inspection Team remain in progress. Should the NRC find a deficiency in SCE's performance, SCE could be subject to additional regulatory action by the NRC, and the findings could be taken into consideration in the CPUC regulatory proceedings described below. In March 2012, the NRC issued a confirmatory action letter that required NRC permission to restart Unit 2 and Unit 3 and outlined actions SCE must complete. Each Unit will only be restarted when repairs and appropriate mitigation plans on that Unit are completed in accordance with the NRC's letter, and SCE is satisfied that it is safe to do so.

In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million when adjusted 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 $592 million through March 31, 2012 on the steam generator replacement project. Those expenditures remain subject to CPUC review upon submission of SCE's final costs for the overall project. Replacement power costs are recovered through the ERRA balancing account, subject to reasonableness review. Replacement power costs for outages associated with the steam generator inspection and repair (commencing on February 1 for Unit 3 and March 5 for Unit 2) through March 31, 2012 were approximately $30 million. Total replacement power costs will not be known until the Units are returned to service, but costs for power are likely to be higher during the summer months should replacement power still be required at that time. Through mid-April 2012, incremental inspection and repair costs totaled $30 million. Subject to NRC review under the confirmatory action letter and any new developments that may result from further analysis, testing and inspection, SCE's estimated share of the total incremental inspection and repair costs associated with returning the units to service remains uncertain, but is currently projected to be in the range of $55 million to $65 million.

The steam generators were supplied by Mitsubishi Heavy Industries (“MHI”) and are warranted for an initial period of 20 years from acceptance. Subject to certain exceptions, the purchase agreement obligates MHI to repair or replace defective items, sets forth specified damages for certain repairs, and provides that MHI's liability under the purchase agreement is generally limited to $137 million in the aggregate and excludes consequential damages, defined to include the cost of replacement power.

2013 Cost of Capital Application

In April 2012, SCE filed its 2013 cost of capital application requesting a ratemaking capital structure of 43% long-term debt, 9% preferred equity and 48% common equity consistent with the current capital structure. In addition, SCE is proposing to reduce its current cost of capital as follows: cost of long-term debt from 6.22% to 5.53%, authorized cost of preferred equity from 6.01% to 5.86% and authorized return on common equity from 11.5% to 11.1%. SCE estimates that this request will result in a revenue requirement reduction of $128 million. The application requests continuation of the current multi-year

mechanism, which would retain the authorized capital structure through 2015. The cost of capital will be subject to annual adjustments if certain thresholds are reached. SCE is seeking a CPUC decision on its application by the end of 2012.

Capital Program

During the first three 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 $839 million during the first three months of 2012 compared to $765 million during the same period in 2011.

As discussed under "Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2011 MD&A, SCE continues to project that 2012 capital expenditures will be in the range of $4.4 billion to $5.0 billion and 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; and other factors.

Management Overview of EMG

EMG's operating results were lower in the first quarter of 2012 compared to the first quarter of 2011 due to lower realized energy and capacity prices at its coal plants and lower generation 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 from Midwest Generation's plants has been correspondingly affected. 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. EMG expects that Midwest Generation's average fuel cost ($/MWh) will increase by approximately one-third in 2012.

At March 31, 2012, EME and its subsidiaries without contractual dividend restrictions, had corporate cash and cash equivalents of $927 million and Midwest Generation had cash and cash equivalents of $230 million and $500 million of available borrowing capacity under its credit facility maturing in June 2012. EME terminated its revolving credit facility in February 2012, and there can be no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity. Any replacements of these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be able to, replace these credit lines or any portion of them. In conjunction with the termination of its credit facility, EME entered into replacement letter of credit facilities secured by cash collateral. EME had $3.7 billion of unsecured notes outstanding at March 31, 2012, $500 million of which mature in 2013.

Unless energy and capacity prices increase substantially, EMG expects that it will incur further reductions in cash flow and losses in years subsequent to 2012 as well as in 2012, and a continuation of these adverse trends coupled with pending debt maturities and the need to retrofit its plants to comply with governmental regulations will strain EMG's liquidity. To address such scenario, EMG would need to consider all options available to it, including potential sales of assets or restructurings or reorganization of the capital structure of EME and its subsidiaries.

Midwest Generation Environmental Compliance Plans and Costs

During the first quarter of 2012, Midwest Generation continued to develop and implement a compliance program that includes the operation of activated carbon injection systems, 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.

EMG has decided to shut down its Fisk and Crawford Stations in September 2012. The shut downs also have been approved by PJM, the regional transmission organization that controls the area where these plants are located. In total, Midwest Generation estimates that 150 to 180 employees will be affected. The timing and amount of severance benefits, if any, will be determined after completion of an ongoing review of personnel based on seniority and other factors. Severance benefits are not required under the existing collective bargaining agreement. Midwest Generation has sold capacity forward through May 31, 2015 for both Fisk and Crawford. However, Midwest Generation has not sold its full capacity forward during those periods. Midwest Generation would expect to cover its capacity obligations associated with the Fisk and Crawford units through a combination of improved fleet performance, fleet capacity not previously sold forward and, if necessary, market transactions. In connection with the shut down of these stations, EMG expects to receive a tax deduction equal to its tax basis in the facilities, although realization of these tax benefits may not occur for several years. At March 31, 2012, the tax basis of the Fisk and Crawford Stations were $64 million and $87 million, respectively.

Decisions regarding whether or not to proceed with retrofitting any particular remaining units to comply with CPS

requirements for SO₂emissions, 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 until required to shut down by applicable regulations or operate with reduced output.

Based on work to date, Midwest Generation estimates the cost of retrofitting the large stations (Powerton, Joliet Units 7 and 8 and Will County) using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO₂ emissions, and the associated upgrading of existing particulate removal systems, would be up to approximately $628 million. The cost of retrofitting Joliet Unit 6 is not included in the large unit amounts as it is less likely that Midwest Generation will make retrofits for this unit. 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. 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

Homer City is not expected to have sufficient cash flow to meet its obligations, including funding capital improvements. Homer City made the required April 1, 2012 senior rent payment but did not make the April 1, 2012 payment of equity rent. On March 30, 2012, Homer City 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's liquidity has continued to deteriorate during the first quarter of 2012. Absent a working capital loan or other infusion of cash, Homer City is not expected to have sufficient cash flow to meet its operating expenses and other obligations either in the near term or during 2012, including the rent payment due on October 1, 2012. This may require Homer City to temporarily suspend plant operations until sufficient working capital is obtained. For further discussion of the Homer City lease, see "Edison International Overview—Management Overview of EMG—Homer City Lease" in the year-ended 2011 MD&A.

Homer City has been engaged in discussions with the owner-lessors through GECC, beneficial owner of a majority of the owner-participants, regarding the funding of capital improvements at the Homer City plant and transfer to an affiliate of GECC of the economic benefit and majority ownership of all the operating assets of Homer City. On March 29, 2012, Homer City and GECC entered into an Implementation Agreement (the "Agreement") with respect to the Homer City plant. As addressed by the Agreement, an affiliate of the GECC-controlled owner-lessors of the Homer City plant has entered into an engineering, procurement and construction agreement and is in the process of executing related agreements for the construction of environmental improvements. GECC will have discretion over all decisions related to such agreements. Homer City agreed to conduct its business as set forth in the Agreement and to use commercially reasonable efforts to provide assistance to GECC and its affiliates in connection with the construction agreements. The Agreement also requires Homer City, at the request of GECC, to enter into one or more implementation transactions, as defined in the Agreement, for the divestiture of its leasehold interest in the Homer City plant (and, under certain circumstances, related assets and liabilities as specified) and to assist GECC in obtaining certain third-party consents or waivers. Homer City and GECC also agreed to enter into a transition services agreement in connection with any implementation transaction. The estimated cost of installing SO₂ and particulate emissions control equipment for Units 1 and 2 of the Homer City plant is expected to be approximately $700 million to $750 million. On April 2, 2012, Homer City received the permit to construct such improvements from PADEP. There is no assurance that Homer City and GECC will actually consummate a divestiture transaction as contemplated by the Agreement.

Certain divestitures of Homer City's leasehold interest in the plant are subject to consent rights of the holders of the secured lease obligation bonds issued in connection with the original sale-leaseback transaction. GECC is currently engaged in discussions and has reached an agreement in principle on a non-binding restructuring term sheet with certain of the holders of the secured lease obligation bonds regarding amendments to the terms of the 8.137% Senior Secured Bonds due 2019 and the 8.734% Senior Secured Bonds due 2026, each issued by Homer City Funding LLC. Even though an agreement in principle has been reached with certain holders of secured lease obligation bonds, that agreement may not be approved by the secured lease obligation bondholders as required under the operative documents to effectuate the necessary modifications to the terms of the bonds. If an agreement to modify the terms of the bonds is not approved and consummated in a timely manner, then the protections of Chapter 11 of the U.S. Bankruptcy Code may be necessary.

Environmental Developments

For a discussion of environmental developments, see "Edison International Notes to Consolidated Financial Statements—Note 10. Environmental Developments."

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.

During the first quarter of 2012, SCE classified revenues and costs related to EdisonSmartConnect^®, San Onofre steam generator replacement project and similar 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 table presented below reflects a reclassification of the revenues and costs for the first quarter of 2011 consistent with the presentation in 2012. The reclassification of revenues and costs had no impact on earnings.

The following table is a summary of SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities.



	Three months ended March 31, 2012								Three months ended March 31, 2011
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated
Operating revenue	$	1,456		$	956	$	2,412		$	1,405		$	827	$	2,232
Fuel and purchased power	—			692		692			—			584		584
Operations and maintenance	588			263		851			542			242		784
Depreciation decommissioning and amortization	389			—		389			344			—		344
Property taxes and other	82			1		83			76			1		77
Total operating expenses	1,059			956		2,015			962			827		1,789
Operating income	397			—		397			443			—		443
Net interest expense and other	(97		)	—		(97		)	(84		)	—		(84		)
Income before income taxes	300			—		300			359			—		359
Income tax expense	99			—		99			123			—		123
Net income	201			—		201			236			—		236
Dividends on preferred and preference stock	19			—		19			14			—		14
Net income available for common stock	$	182		$	—	$	182		$	222		$	—	$	222
Core Earnings¹						$	182							$	222
Non-Core Earnings						—								—
Total SCE GAAP Earnings						$	182							$	222


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

Utility Earning Activities

During the first quarter of 2012, SCE recognized revenue from CPUC activities largely based on 2011 authorized base revenue requirements included in customer rates pending the outcome of the GRC. 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. 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).

Utility earning activities were primarily affected by the following:


•	SCE had higher operating revenue of $51 million, primarily due to the following:


•	$40 million increase was primarily due to revenue related to authorized CPUC projects not included in SCE's GRC process including the EdisonSmartConnect^®project, San Onofre steam generator replacement project and the Solar Photovoltaic project.


•	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.

•

Higher operation and maintenance expense of $46 million was primarily due to $35 million of costs related to the 2012 San Onofre Unit 2 scheduled maintenance and refueling outage as well as $20 million related to the steam generator inspection and repair at San Onofre. These increases were partially offset by transmission and distribution reductions and EdisonSmartConnect^® benefits realized. See "Edison International Overview—Management Overview of SCE—San Onofre Outage, Inspection and Repair Issues" for further information.


•	Higher depreciation, decommissioning and amortization expense of $45 million was primarily related to increased transmission and distribution investments.

•

Higher net interest expense and other of $13 million was primarily due to higher outstanding balances on long-term debt and a lower AFUDC capitalization rate in 2012 mainly driven by lower cost of financing resulting from an increase in the use of short-term debt. For details of other income and expenses, see "Edison International Notes to Consolidated Financial Statements—Note 15. Other Income and Expenses."


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

Utility Cost-Recovery Activities

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

•

Higher purchased power expense of $108 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 lower generation in 2012 from San Onofre. These increases were offset by lower power prices in 2012.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $2.3 billion and $2.1 billion for the three months ended March 31, 2012 and 2011 respectively. The increase in revenue reflects:


•	a sales volume increase of $288 million 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 $105 million resulting from a rate adjustment beginning on June 1, 2011, primarily reflecting the refund 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).

Income Taxes

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



	Three months ended March 31,
(in millions)	2012			2011
Income before income taxes	$	300		$	359
Provision for income tax at federal statutory rate of 35%	$	105		$	125
Increase (decrease) in income tax from:
State tax – net of federal benefit	10			12
Property-related	(10		)	(11		)
Other	(6		)	(3		)
Total income tax expense	$	99		$	123
Effective tax rate	33.0		%	34.3		%

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

SCE has two credit facilities: a $2.3 billion five-year credit facility that matures in February 2013 and a $500 million three-year credit facility that matures in March 2013. SCE expects to complete negotiations for a replacement credit facility with substantially similar terms and current market rates in 2012.



(in millions)	Credit Facilities
Commitment	$	2,796
Outstanding commercial paper supported by credit facilities	(330		)
Outstanding letters of credit	(63		)
Amount available	$	2,403

Debt Covenant

SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At March 31, 2012, SCE's debt to total capitalization ratio was 0.48 to 1.

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. 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 March 31, 2012, SCE's 13-month weighted-average common equity component of total capitalization was 50.0% resulting in the capacity to pay $377 million in additional dividends to Edison International.

During the first quarter of 2012, SCE made $116 million in dividend payments to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the level of capital expenditures, operating cash flows and earnings.

Margin and Collateral Deposits

Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. Future collateral requirements may differ from the requirements at March 31, 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.

The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of March 31, 2012.



(in millions)
Collateral posted as of March 31, 2012¹	$	164
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade	140
Posted and potential collateral requirements²	$	304


¹	Collateral provided to counterparties and other brokers consisted of $81 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $20 million of cash reflected in "Other current assets" on the consolidated balance sheets and $63 million in letters of credit.


²	There would be no increase to SCE's total posted and potential collateral requirements based on SCE's forward positions as of March 31, 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.



	Three months ended March 31,
(in millions)	2012			2011
Net cash provided by operating activities	$	775		$	672
Net cash provided by financing activities	500			190
Net cash used by investing activities	(1,269		)	(1,066		)
Net increase (decrease) in cash and cash equivalents	$	6		$	(204	)

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased $103 million in the first quarter of 2012 compared to the same period in 2011. The increase in cash flows provided by operating activities was primarily due to the timing of cash receipts and disbursements related to working capital items, partially offset by lower net tax receipts in 2012.

Net Cash Provided by Financing Activities

The following table summarizes cash provided by financing activities for the three months ended March 31, 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."



	Three months ended March 31,
(in millions)	2012			2011
Issuances of preference stock, net	$	345		$	123
Issuances of first and refunding mortgage bonds, net	391			—
Payments of common stock dividends to Edison International	(116		)	(115		)
Payments of preferred and preference stock dividends	(15		)	(13		)
Net issuances of commercial paper¹	(89		)	200
Other	(16		)	(5		)
Net cash provided by financing activities	$	500		$	190


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

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 $1.2 billion and $1.0 billion for the three months ended March 31, 2012 and 2011, respectively (see "SCE: 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 $82 million and $47 million for the three months ended March 31, 2012 and 2011, respectively.

Contractual Obligations and Contingencies

Contingencies

SCE has contingencies related to the 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 March 31, 2012, SCE had identified 25 material sites for remediation and recorded an estimated minimum liability of $43 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."

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 $1.3 billion and $936 million at March 31, 2012 and December 31, 2011, respectively. The increase in the net liability was related to changes in unrealized losses on economic hedging activities primarily due to declining power and natural gas prices. 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 March 31, 2012, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:



	March 31, 2012
(in millions)	Exposure²		Collateral			Net Exposure
S&P Credit Rating¹
A or higher	$	101	$	—		$	101
A-	1		—			1
Not rated³	14		(4		)	10
Total	$	116	$	(4	)	$	112


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.

EDISON MISSION GROUP

RESULTS OF OPERATIONS

EMG primarily operates in one line of business, independent power production. The following table is a summary of competitive power generation results of operations for the periods indicated.



	Three months ended March 31,
(in millions)	2012			2011
Competitive power generation operating revenues	$	444		$	552
Fuel	206			182
Operation and maintenance	241			281
Depreciation and amortization	68			73
Loss on disposal and asset impairments	14			—
Total operating expenses	529			536
Operating income (loss)	(85		)	16
Interest and dividend income	1			2
Equity in loss from unconsolidated affiliates – net	(1		)	(5		)
Other income (expense), net	—			3
Interest expense	(86		)	(80		)
Loss from continuing operations before income taxes	(171		)	(64		)
Income tax benefit	(90		)	(46		)
Loss from continuing operations	(81		)	(18		)
Loss from discontinued operations–net of tax	(1		)	(2		)
Net loss	(82		)	(20		)
Less: Net income attributable to noncontrolling interests	(2		)	—
Net loss available for common stock	$	(84	)	$	(20	)
Core Losses¹	$	(60	)	$	(8	)
Non-Core Losses:
Homer City	(23		)	(10		)
Discontinued Operations	(1		)	(2		)
Total EMG GAAP Losses	$	(84	)	$	(20	)


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

EMG's core loss in the first quarter 2012 increased compared to the first quarter 2011 primarily due to the following pre-tax items:


•	$95 million decrease in Midwest Generation results primarily due to lower average realized prices, lower capacity prices, higher fuel prices and reduced generation.


•	$6 million increase in interest expense due to new energy project financings ($2 million) and lower capitalized interest ($4 million).

The decrease was partially offset by the following pre-tax items:


•	$4 million increase in energy trading due to increased revenues from trading power contracts and congestion.


•	$9 million increase in renewable energy income due to the increase in wind projects in operation coupled with higher generation and more favorable wind conditions.

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

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



	Three months ended March 31,
(in millions)	2012			2011
Midwest Generation plants	$	(40	)	$	55
Homer City plant	(38		)	(16		)
Renewable energy projects	30			21
Energy trading	19			15
Big 4 projects	(1		)	2
Sunrise	—			(7		)
Westside projects	(2		)	—
Leveraged lease income	1			1
Other projects	2			4
	(29		)	75
Corporate administrative and general	(33		)	(36		)
Corporate depreciation and amortization	(6		)	(6		)
AOI¹	$	(68	)	$	33

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 March 31,
(in millions)	2012			2011
AOI	$	(68	)	$	33
Less:
Equity in loss of unconsolidated affiliates	(1		)	(5		)
Dividend income from projects	—			1
Production tax credits	19			18
Other income, net	1			3
Net income attributable to noncontrolling interests	(2		)	—
Operating Income (Loss)	$	(85	)	$	16

Adjusted Operating Income from Consolidated Operations

Midwest Generation Plants

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



	Three months ended March 31,
(in millions)	2012			2011
Operating Revenues	$	233		$	351
Operating Expenses
Fuel	117			126
Plant operations	109			118
Plant operating leases	19			19
Depreciation and amortization	21			29
Loss on disposal and asset impairments	2			—
Administrative and general	5			6
Total operating expenses	273			298
Operating Income (Loss)	(40		)	53
Other Income	—			2
AOI	$	(40	)	$	55
Statistics
Generation (in GWh)	5,339			7,470

AOI from the Midwest Generation plants decreased $95 million for the first quarter of 2012 compared to the first quarter of 2011. The 2012 decrease in AOI was primarily attributable to lower average realized energy prices, lower capacity prices, higher fuel prices, and reduced generation. Reduced generation resulted from lower economic dispatch, increased planned maintenance in 2012 versus 2011 and a weather anomaly seen in March of 2012 when unseasonably warm weather increased river temperature to levels that impacted the thermal discharge limits of the Joliet and Will County units.

Included in operating revenues were unrealized gains of $4 million and none for the first quarters of 2012 and 2011, respectively. Unrealized gains in the first quarter of 2012 were primarily attributable to natural gas futures contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of operations. Unrealized gains also included the ineffective portion of hedge contracts at the Midwest Generation plants attributable to changes in the difference between energy prices at the Northern Illinois Hub (the settlement point under forward contracts) and the energy prices at the Midwest Generation plants' busbars (the delivery point where power generated by the Midwest Generation plants is delivered into the transmission system) resulting from marginal losses.

Included in fuel costs were unrealized gains (losses) of $3 million and $(1) million during the first quarters of 2012 and 2011, respectively, due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into as hedges of the variable fuel price component of rail transportation costs.

Homer City

The following table presents additional data for the Homer City plant, which is being classified as a non-core earnings item under "Edison International Overview—Highlights of Operating Results":



	Three months ended March 31,
(in millions)	2012			2011
Operating Revenues	$	100		$	115
Operating Expenses
Fuel	84			52
Plant operations	19			47
Plant operating leases	19			25
Depreciation and amortization	—			5
Loss on disposal and asset impairments	11			—
Administrative and general	5			2
Total operating expenses	138			131
Operating Loss	(38		)	(16		)
AOI	$	(38	)	$	(16	)
Statistics
Generation (in GWh)	2,607			1,943

AOI from the Homer City plant decreased $22 million for the first quarter of 2012 compared to the first quarter of 2011. The 2012 decrease in AOI was primarily attributable to lower energy margins, partially offset by a decline in plant maintenance costs due to outages at Units 1 and 2 during the first quarter of 2011. Lower energy margins were due to lower average realized energy prices and higher coal and emission allowance costs. During the first quarter of 2012, Homer City incurred capital expenditures related to environmental improvements. Those environmental improvements did not increase the fair value of the leasehold interest due to the issues discussed in "Management Overview of EMG" therefore, the costs were fully impaired. In addition, plant operating lease expense decreased in the first quarter of 2012 compared to the first quarter of 2011 as a result of the impairment of prepaid rent related to the Homer City lease in the fourth quarter of 2011. The impairment resulted in a new levelized rent schedule.

Seasonality—Coal Plants

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

Renewable Energy Projects

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



	Three months ended March 31,
(in millions)	2012			2011
Operating Revenues	$	72		$	52
Production Tax Credits	19			18
	91			70
Operating Expenses
Plant operations	19			18
Depreciation and amortization	39			31
Administrative and general	2			1
Total operating expenses	60			50
Equity in income from unconsolidated affiliates	1			—
Other Income	—			1
Net Income Attributable to Noncontrolling Interests	(2		)	—
AOI¹	$	30		$	21
Statistics
Generation (in GWh)²	1,746			1,385

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 EMG. Generation excluding unconsolidated projects was 1,516 GWh and 1,202 GWh in the first quarter of 2012 and 2011, respectively.

AOI from renewable energy projects increased $9 million in the first quarter of 2012 compared to the first quarter of 2011. The 2012 increase was primarily attributable to projects that achieved commercial operation after the first quarter of 2011 and increased generation at other projects due to more favorable wind conditions during 2012. Net income attributable to noncontrolling interests was primarily due to the Capistrano Wind equity capital transaction. 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."

Energy Trading

AOI from energy trading activities increased $4 million for the first quarter of 2012, compared to the first quarter of 2011 mainly due to higher revenues from power trading activities and congestion.

Adjusted Operating Income from Other Projects

Sunrise Project. AOI from the Sunrise project increased $7 million during the first quarter of 2012 compared to the first quarter of 2011 primarily due to higher repairs and maintenance costs for a major overhaul in 2011.

Seasonality. EMG's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.

Interest Income (Expense)



	Three months ended March 31,
(in millions)	2012			2011
Interest income	$	—		$	1
Interest expense, net of capitalized interest
EME debt	(67		)	(62		)
Nonrecourse debt	(19		)	(18		)
	$	(86	)	$	(80	)

EMG's interest expense increased $6 million for the first quarter of 2012 compared to the first quarter of 2011. The 2012 increase in interest expense was primarily due to lower capitalized interest and higher debt balances from new project financings. Capitalized interest was $6 million and $10 million for the first quarters of 2012 and 2011, respectively. The 2012 decrease was due to fewer projects under construction in 2012 compared to 2011.

Income Taxes

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



	Three months ended March 31,
(in millions)	2012			2011
Loss from continuing operations before income taxes	$	(171	)	$	(64	)
Provision for income tax benefit at federal statutory rate of 35%	$	(60	)	$	(22	)
Increase (decrease) in income tax from:
State tax benefit – net of federal tax expense	(14		)	(5		)
Tax credits, net	(19		)	(18		)
Property-related	—			(1		)
Other	3			—
Total income tax benefit from continuing operations	$	(90	)	$	(46	)
Effective tax rate	53		%	72		%

EMG's effective tax rates were impacted by production tax credits and estimated state income tax benefits allocated from Edison International. Estimated state income tax benefits allocated from Edison International of $3 million and $2 million were recognized for the three months ended March 31, 2012 and 2011, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

The following table summarizes available liquidity at March 31, 2012:



(in millions)	Cash and Cash Equivalents		Available Under Credit Facility¹		Total Available Liquidity
EME as a holding company	$	711	$	—	$	711
EME subsidiaries without contractual dividend restrictions	216		—		216
EME corporate cash and cash equivalents	927		—		927
EME subsidiaries with contractual dividend restrictions
Midwest Generation²	230		500		730
Homer City	84		—		84
Other EME subsidiaries	66		—		66
Other EMG subsidiaries	58		—		58
Total	$	1,365	$	500	$	1,865

Midwest Generation's existing credit facility matures in June 2012. For further discussion, see "Edison International Overview—Management Overview of EMG" and refer to "Item 1A. Risk Factors—Risks Relating to EMG—Liquidity Risks" in Edison International's annual report on Form 10-K for the year ended December 31, 2011. In the first quarter of 2012, EME terminated its $564 million revolving credit facility and entered into replacement letter of credit facilities secured by cash collateral. For additional information, see "Edison International Notes to Consolidated Financial Statements—Note 5—Debt and Credit Agreements—2012 Letter of Credit Facilities."


²	Cash and cash equivalents are available to meet Midwest Generation's operating and capital expenditure requirements.

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

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 "—Dividend Restrictions in Major Financings."

Senior notes in the principal amount of $500 million, which bear interest at 7.50% per annum, are due in June 2013. EME may from time to time, seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, open market purchases, privately negotiated transactions or otherwise, depending on prevailing market conditions, EME's liquidity requirements, contractual restrictions and other factors.

For information regarding third-party capital obtained in February 2012 to finance the development of a portion of EMG's wind portfolio, see "Edison International Overview—Management Overview of EMG—EMG's Renewable Energy Activities" in the MD&A and "Edison International Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities—Projects or Entities that are Consolidated—Capistrano Wind Equity Capital."

Capital Investment Plan

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



(in millions)	April through December 2012		2013		2014
Midwest Generation Plants
Environmental¹	$	27	$	102	$	311
Plant capital	12		47		16
Homer City Plant	34		23		14
Walnut Creek Project	179		40		—
Renewable Energy Projects	105		1		2
Other capital	17		19		15
Total	$	374	$	232	$	358


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' projected environmental expenditures would retrofit 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. Decisions regarding 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, remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. 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.

Homer City Capital Expenditures

The capital investment plan set forth above does not include environmental capital expenditures to retrofit the Homer City plant because Homer City does not have the funds for retrofits and will be dependent on external funding. Subject to the availability of capital, plant capital expenditures for Homer City are projected to be $34 million for the remaining nine months of 2012 and $23 million and $14 million in 2013 and 2014, respectively. See "Edison International Overview—Management Overview of EMG—Homer City Lease."

Renewable Energy Projects

At March 31, 2012, EMG's development pipeline of potential wind projects was approximately 1,300 MW. Future development of the wind portfolio is dependent on the availability of third-party capital. To the extent that third-party capital is available, the success of development efforts will depend upon, among other things, obtaining permits and agreements necessary to support an investment.

Historical Segment Cash Flows

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



	Three months ended March 31,
(in millions)	2012			2011
Operating cash flow from continuing operations	$	(96	)	$	116
Operating cash flow from discontinued operations	(1		)	(2		)
Net cash provided (used) by operating activities	(97		)	114
Net cash provided by financing activities	275			103
Net cash used by investing activities	(174		)	(108		)
Net increase (decrease) in cash and cash equivalents	$	4		$	109

Net Cash Provided (Used) by Operating Activities

Net cash used by operating activities from continuing operations decreased $212 million in the first quarter of 2012 compared to the first quarter of 2011 primarily due to decreased operating income due to declining energy prices, increased operating costs and higher interest payments due to new energy project financings.

Net Cash Provided by Financing Activities

Net cash provided by financing activities from continuing operations increased $172 million in the first quarter of 2012 compared to the first quarter of 2011 primarily due to cash contributions from noncontrolling interests and the timing of financings and repayment of debt as summarized in the following table:



	Three months ended March 31,
(in millions)	2012			2011
Cash contributions from noncontrolling interests	$	238		$	—
Long-term debt financings
Renewable energy projects	—			76
Walnut Creek project	54			—
Short-term debt financings
Renewable energy projects	—			32
Debt repayments
Renewable energy projects	(4		)	(6		)
Other projects	(3		)	(2		)
Financing costs and others	(10		)	3
Total cash provided by financing activities	$	275		$	103

Net Cash Used by Investing Activities

Net cash used by investing activities from continuing operations decreased $66 million in the first quarter of 2012 compared to the first quarter of 2011 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:



	Three months ended March 31,
(in millions)	2012			2011
Capital expenditures
Midwest Generation plants
Environmental	$	(7	)	$	(21	)
Plant capital	(3		)	(10		)
Homer City plant	(7		)	(4		)
Walnut Creek project	(55		)	—
Renewable energy projects	(13		)	(67		)
Other capital expenditures	(1		)	(3		)
Investments in other assets	(3		)	(1		)
Collateral for letter of credit facilities	(74		)	—
Other investing activities	(11		)	(2		)
Total cash used in investing activities	$	(174	)	$	(108	)

Credit Ratings

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



	Moody's Rating	S&P Rating	Fitch Rating
EME¹	Caa3	CCC+	C
Midwest Generation²	B2	B	CCC
EMMT	Not Rated	CCC+	Not Rated


¹	Senior unsecured rating.


²	First priority senior secured rating.

All the above ratings are on negative outlook. EMG cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EMG notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

EMG does not have any "rating triggers" contained in subsidiary financings that would result in 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, EMG hedges a portion of its electricity price exposure through EMMT. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. 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 March 31, 2012, if wholesale energy prices change or if EMMT enters into additional transactions. EMG estimates that margin and collateral requirements for energy and congestion contracts outstanding as of March 31, 2012 could increase by approximately $19 million over the remaining life of the contracts using a 95% confidence level.

Debt Covenants and Dividend Restrictions

Key Ratios of EMG's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EMG's principal subsidiaries required by financing arrangements at March 31, 2012 or for the 12 months ended March 31, 2012:



Subsidiary	Financial Ratio	Covenant	Actual
Midwest Generation (Midwest Generation plants)	Debt-to-Capitalization Ratio	Less than or equal to 0.60 to 1	0.13 to 1
Homer City (Homer City plant)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	1.09 to 1

As indicated above, the actual senior rent service coverage ratio of Homer City was below the covenant threshold for the 12 months ended March 31, 2012, and Homer City also did not meet the threshold for the prospective two 12-month periods, which currently precludes Homer City from making distributions, including repayment of certain intercompany loans and from paying the equity portion of the rent payment. On March 30, 2012, Homer City 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 . For additional information, see "Edison International Overview—Management Overview of EMG—Homer City Lease."

For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "Edison Mission Group—Liquidity and Capital Resources—Debt Covenants and Dividend Restrictions" in the year-ended 2011 MD&A.

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

EME is restricted under applicable agreements from selling or disposing of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding the sale or disposition in question. At March 31, 2012, the maximum permissible sale or disposition of EME assets was $789 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

Contingencies

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

Off-Balance Sheet Transactions

For a discussion of EMG's off-balance sheet transactions, refer to "EMG: Liquidity and Capital Resources—Off-Balance Sheet Transactions" in the year-ended 2011 MD&A. There have been no significant developments with respect to EMG's 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."

MARKET RISK EXPOSURES

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

Derivative Instruments

Unrealized Gains and Losses

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



	Three months ended March 31,
(in millions)	2012		2011
Midwest Generation plants
Non-qualifying hedges	$	6	$	(1	)
Ineffective portion of cash flow hedges	1		—
Homer City plant
Non-qualifying hedges	—		1
Ineffective portion of cash flow hedges	—		1
Total unrealized gains	$	7	$	1

At March 31, 2012, cumulative unrealized gains of $14 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($13 million for the remainder of 2012 and $1 million for 2013).

Fair Value Disclosures

In determining the fair value of EMG's derivative positions, EMG uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EMG's derivative instruments, see "Edison International Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements" and "—Note 6. Derivative Instruments and Hedging Activities," respectively.

Commodity Price Risk

Energy Price Risk

Energy and capacity from the coal plants are sold under terms, including price, duration and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Power is sold into PJM at spot prices based upon locational marginal pricing. 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 locations indicated for the first quarters of 2012 and 2011:



	24-Hour Average Historical Market Prices¹
	2012		2011
Midwest Generation plants
Northern Illinois Hub	$	27.20	$	34.01
Homer City plant
PJM West Hub	$	31.82	$	46.48
Homer City Busbar	29.01		41.12


¹	Energy prices were calculated at the Northern Illinois Hub and Homer City Busbar delivery points and the PJM West 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 and PJM West Hub at March 31, 2012:



	24-Hour Forward Energy Prices¹
	Northern Illinois Hub		PJM West Hub
2012
April	$	23.05	$	28.65
May	23.38		28.90
June	25.44		32.19
July	29.99		36.55
August	30.61		37.28
September	23.22		30.35
October	22.84		29.83
November	23.16		30.82
December	26.54		35.37
2013 calendar "strip"²	$	29.64	$	37.44


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


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

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

EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services contracts) at March 31, 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	4,719	$	39.18	1,020	$	40.43
Homer City plant^3,4	112	54.12		—	—
Total	4,831			1,020

The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions are not directly comparable to the 24-hour Northern Illinois Hub or PJM West Hub prices set forth above.


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


³	2012 includes hedging activities entered into by EMMT for the Homer City plant at the PJM APS Zone that are not designated under the intercompany agreements with Homer City due to limitations under the sale-leaseback transaction documents.


⁴	The average price/MWh includes 158 MW of capacity for periods ranging from April 1, 2012 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.

Capacity Price Risk

Under the RPM, capacity commitments are made in advance to provide a long-term pricing signal for construction of capacity resources. The following table summarizes the status of capacity sales for Midwest Generation and Homer City at March 31, 2012:



					RPM Capacity Sold in Base Residual Auction			Other Capacity Sales, Net of Purchases³				Aggregate Average Price per MW-day
	Installed Capacity MW	Unsold Capacity¹ MW		Capacity Sold² MW	MW	Price per MW-day		MW		Average Price per MW-day		Aggregate Average Price per MW-day
April 1, 2012 to May 31, 2012
Midwest Generation	5,477	(555	)	4,922	4,582	$	110.00	340		$	98.92	$	109.23
Homer City	1,884	(163	)	1,721	1,771	110.00		(50	)	30.00		112.32
June 1, 2012 to May 31, 2013
Midwest Generation	5,477	(773	)	4,704	4,704	16.46		—		—		16.46
Homer City	1,884	(355	)	1,529	1,736	133.37		(207	)	8.16		150.35
June 1, 2013 to May 31, 2014
Midwest Generation	5,477	(827	)	4,650	4,650	27.73		—		—		27.73
Homer City	1,884	(104	)	1,780	1,780	226.15		—		—		221.03		⁴
June 1, 2014 to May 31, 2015
Midwest Generation	5,477	(852	)	4,625	4,625	125.99		—		—		125.99
Homer City	1,884	(190	)	1,694	1,694	136.50		—		—		136.50


¹	Capacity not sold arises from: (i) capacity retained to meet forced outages under the RPM auction guidelines, and (ii) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.


²	Excludes 158 MW of capacity for periods ranging from April 1, 2012 to May 31, 2012 at Homer City sold in conjunction with load requirements services contracts.


³	Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.


⁴	Includes the impact of a 100 MW capacity swap transaction executed prior to the base residual auction at $135 per MW-day.

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

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

Effective April 16, 2012, EMMT assigned the awards it received related to Homer City capacity to Homer City effective as of June 1, 2012. As a result of the financial outlook of Homer City, as previously discussed, EME's subsidiary, EMMT, has ceased to enter into hedging activities related to future power sales, but continues to enter into short-term energy transactions on behalf of Homer City pursuant to an intercompany agreement. Those transactions are generally back-to-back transactions in which EMMT enters into a transaction with a third party as a principal and then enters into an equivalent transaction with Homer City.

Basis Risk

During the three months ended March 31, 2012 and 2011, day-ahead prices at the Homer City busbar were lower than those at the PJM West Hub by an average of 9% and 12%, respectively. During the three months ended March 31, 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%, higher by 3% and higher by 1%, respectively. During the three months ended March 31, 2011, day-ahead prices at the individual busbars of the Midwest Generation plants were lower compared to the AEP/Dayton Hub, Indiana Hub (Cinergy Hub) and Northern Illinois Hub by an average of 11%, 6% and 1%, respectively. Differences in day-ahead pricing between the individual busbars of the Homer City and Midwest Generation plants generally arise due to transmission congestion.

Credit Risk

The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EMG's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At March 31, 2012, the balance sheet exposure as described above, by the credit ratings of EMG's counterparties, was as follows:



	March 31, 2012
(in millions)	Exposure²		Collateral			Net Exposure
Credit Rating¹
A or higher	$	81	$	(8	)	$	73
A-	3		—			3
BBB+	1		—			1
BBB-	4		—			4
Below investment grade	78		(77		)	1
Total	$	167	$	(85	)	$	82


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


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

The credit risk exposure set forth in the above table is composed of $50 million of net accounts receivable and payables and $117 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EMG's subsidiaries have posted a $76 million cash margin in the aggregate with PJM, NYISO, MISO, clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EMG to credit risk of the related entities.

The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 67% of EMG's consolidated operating revenues for the three months ended March 31, 2012. At March 31, 2012, EMG's account receivable due from PJM was $41 million.

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

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EMG mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. For further details, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements" and "—Note 6. Derivative Instruments and Hedging Activities."

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 $5 million and $2 million for the three months ended March 31, 2012 and 2011, respectively. Results included consolidated tax benefits of $4 million and $6 million in 2012 and 2011, respectively, representing differences in the allocation of state income taxes to subsidiaries under tax allocation agreements.

LIQUIDITY AND CAPITAL RESOURCES

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

The following table summarizes the status of the Edison International Parent credit facility (expires in February 2013) at March 31, 2012:



(in millions)	Edison International (parent)
Commitment	$	1,379
Outstanding borrowings	(13		)
Outstanding letters of credit	—
Amount available	$	1,366

Edison International expects to complete negotiations for a replacement credit facility with substantially similar terms and current market rates in 2012.

Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1. At March 31, 2012, Edison International's consolidated debt to total capitalization ratio was 0.56 to 1.

Historical Segment Cash Flows

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



	Three months ended March 31,
(in millions)	2012			2011
Net cash used by operating activities	$	(2	)	$	(69	)
Net cash provided by financing activities	6			72
Net cash provided by investing activities	—			—
Net increase in cash and cash equivalents	$	4		$	3

Net Cash Used by Operating Activities

Net cash used 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.

Net Cash Provided by Financing Activities

Financing activities for the first quarter of 2012 were as follows:


•	Paid $106 million of dividends to Edison International common shareholders.


•	Received $116 million of dividend payments from SCE.

Financing activities for the first quarter of 2011 were as follows:


•	Paid $104 million of dividends to Edison International common shareholders.


•	Received $115 million of dividend payments from SCE.


•	Borrowed $62 million under Edison International's line of credit to fund interim working capital requirements.

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 Contingencies" and "SCE: Liquidity and Capital Resources—Contractual Obligations and Contingencies."

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

For a discussion of Edison International's critical accounting estimates and policies, see "Critical Accounting Estimates and Policies" in the year-ended 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 period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the period, Edison International's disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

Jointly Owned Utility Plant

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

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.

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 first 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
January 1, 2012 to January 31, 2012	737,675	$	40.90	—	—
February 1, 2012 to February 29, 2012	484,676	$	41.31	—	—
March 1, 2012 to March 31, 2012	1,031,072	$	42.83	—	—
Total	2,253,423	$	41.87	—	—



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

ITEM 6. EXHIBITS



Exhibit Number		Description

10.1**		Edison International 2012 Executive Annual Incentive Program

10.2**		Edison International 2012 Long-Term Incentives Terms and Conditions

10.3**		Edison International Executive Incentive Compensation Plan, as amended and restated effective January 1, 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 March 31, 2012, filed on May 2, 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

________________________________________


**	Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)3.

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:	May 2, 2012