SOUTHERN CALIFORNIA EDISON 10Q 2012 Q1 Quarterly report

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 1-2313

________________________

SOUTHERN CALIFORNIA EDISON COMPANY

(Exact name of registrant as specified in its charter)

________________________



California (State or other jurisdiction of incorporation or organization)		95-1240335 (I.R.S. Employer Identification No.)

2244 Walnut Grove Avenue (P.O. Box 800) Rosemead, California (Address of principal executive offices)		91770 (Zip Code)

(626) 302-1212 (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 o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer o	Accelerated filer o	Non-accelerated filer x (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No 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		434,888,104

TABLE OF CONTENTS



GLOSSARY		iii
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS		1
	Consolidated Statements of Income	1
	Consolidated Statements of Comprehensive Income	1
	Consolidated Balance Sheets	2
	Consolidated Statements of Cash Flows	4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS		5
	Note 1. Summary of Significant Accounting Policies	5
	Note 2. Consolidated Statements of Changes in Equity	6
	Note 3. Variable Interest Entities	7
	Note 4. Fair Value Measurements	7
	Note 5. Debt and Credit Agreements	12
	Note 6. Derivative Instruments and Hedging Activities	12
	Note 7. Income Taxes	15
	Note 8. Pension Plans and Postretirement Benefits Other Than Pensions	15
	Note 9. Commitments and Contingencies	16
	Note 10. Environmental Developments	19
	Note 11. Supplemental Cash Flows Information	19
	Note 12. Preferred and Preference Stock	20
	Note 13. Regulatory Assets and Liabilities	20
	Note 14. Other Investments	21
	Note 15. Other Income and Expenses	22
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		23
FORWARD-LOOKING STATEMENTS		23
MANAGEMENT OVERVIEW		24
	Highlights of Operating Results	24
	2012 CPUC General Rate Case	24
	San Onofre Outage, Inspection and Repair Issues	25
	2013 Cost of Capital Application	25
	Capital Program	26
	Environmental Developments	26
RESULTS OF OPERATIONS		26
	Utility Earning Activities	27
	Utility Cost-Recovery Activities	28
	Supplemental Operating Revenue Information	28
	Income Taxes	28
LIQUIDITY AND CAPITAL RESOURCES		29
	Available Liquidity	29
	Regulatory Proceedings	29
	Dividend Restrictions	29
	Margin and Collateral Deposits	29
	Workers Compensation Self-Insurance Fund	30
	Historical Consolidated Cash Flows	30

GLOSSARY

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



2011 Form 10-K		SCE'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
APS		Arizona Public Service Company
ARO(s)		asset retirement obligation(s)
Bcf		billion cubic feet
Big 4		Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
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
CPUC		California Public Utilities Commission
CRRs		congestion revenue rights
DOE		U. S. Department of Energy
ERRA		energy resource recovery account
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGIC		Financial Guarantee Insurance Company
FIP(s)		federal implementation plan(s)
Four Corners		coal fueled electric generating facility located in Farmington, New Mexico in which SCE holds a 48% ownership interest
GAAP		generally accepted accounting principles
GHG		greenhouse gas
Global Settlement		A settlement between Edison International and the IRS that resolves all of SCE's federal income tax disputes and affirmative claims for tax years 1986 through 2002 and related matters with state tax authorities.
GRC		general rate case
IRS		Internal Revenue Service
ISO		Independent System Operator
kWh(s)		kilowatt-hour(s)
MD&A		Management's Discussion and Analysis of Financial Condition and Results of Operations in this report
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 Technology Upgrade
MW		megawatts
MWh		megawatt-hours
NAAQS		national ambient air quality standards
NERC		North American Electric Reliability Corporation
Ninth Circuit		U.S. Court of Appeals for the Ninth Circuit
NO_x		nitrogen oxide

iii



NRC		Nuclear Regulatory Commission
NSR		New Source Review
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
PSD		Prevention of Significant Deterioration
QF(s)		qualifying facility(ies)
ROE		return on equity
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
SCAQMD		South Coast Air Quality Management District
SCE		Southern California Edison Company
SDG&E		San Diego Gas & Electric
SEC		U.S. Securities and Exchange Commission
SIP(s)		state implementation plan(s)
SO₂		sulfur dioxide
SRP		Salt River Project Agricultural Improvement and Power District
US EPA		U.S. Environmental Protection Agency
VIE(s)		variable interest entity(ies)

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



Consolidated Statements of Income	Southern California Edison Company



	Three months ended March 31,
(in millions, unaudited)	2012			2011
Operating revenue	$	2,412		$	2,232
Fuel	77			76
Purchased power	615			508
Operation and maintenance	851			784
Depreciation, decommissioning and amortization	389			344
Property and other taxes	83			77
Total operating expenses	2,015			1,789
Operating income	397			443
Interest income	2			2
Other income	31			38
Interest expense	(121		)	(111		)
Other expenses	(9		)	(13		)
Income before income taxes	300			359
Income tax expense	99			123
Net income	201			236
Less: Dividends on preferred and preference stock	19			14
Net income available for common stock	$	182		$	222



Consolidated Statements of Comprehensive Income

	Three months ended March 31,
(in millions, unaudited)	2012		2011
Net income	$	201	$	236
Other comprehensive income, net of tax:
Pension and postretirement benefits other than pensions:
Amortization of net loss included in net income, net of income tax expense of $3 and $1 for 2012 and 2011, respectively	3		1
Other comprehensive income	3		1
Comprehensive income	$	204	$	237

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



Consolidated Balance Sheets	Southern California Edison Company



(in millions, unaudited)	March 31, 2012		December 31, 2011
ASSETS
Cash and cash equivalents	$	63	$	57
Receivables, less allowances of $76 and $75 for uncollectible accounts at respective dates	641		760
Accrued unbilled revenue	508		519
Inventory	340		350
Prepaid taxes	279		278
Derivative assets	51		65
Regulatory assets	692		494
Other current assets	188		89
Total current assets	2,762		2,612
Nuclear decommissioning trusts	3,853		3,592
Other investments	102		93
Total investments	3,955		3,685
Utility property, plant and equipment, less accumulated depreciation of $7,088 and $6,894 at respective dates	28,133		27,569
Nonutility property, plant and equipment, less accumulated depreciation of $110 and $107 at respective dates	72		73
Total property, plant and equipment	28,205		27,642
Derivative assets	65		70
Regulatory assets	6,124		5,815
Other long-term assets	494		491
Total long-term assets	6,683		6,376








Total assets	$	41,605	$	40,315

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



Consolidated Balance Sheets	Southern California Edison Company



(in millions, except share amounts, unaudited)	March 31, 2012			December 31, 2011
LIABILITIES AND EQUITY
Short-term debt	$	330		$	419
Accounts payable	994			1,319
Accrued taxes	111			49
Accrued interest	125			167
Customer deposits	195			199
Derivative liabilities	254			266
Regulatory liabilities	645			670
Other current liabilities	538			759
Total current liabilities	3,192			3,848
Long-term debt	8,827			8,431
Deferred income taxes	6,166			5,781
Deferred investment tax credits	82			84
Customer advances	141			138
Derivative liabilities	1,135			805
Pensions and benefits	2,356			2,461
Asset retirement obligations	2,651			2,610
Regulatory liabilities	5,103			4,670
Other deferred credits and other long-term liabilities	1,589			1,529
Total deferred credits and other liabilities	19,223			18,078
Total liabilities	31,242			30,357
Commitments and contingencies (Note 9)
Common stock, no par value (560,000,000 shares authorized; 434,888,104 shares issued and outstanding at each date)	2,168			2,168
Additional paid-in capital	600			596
Accumulated other comprehensive loss	(21		)	(24		)
Retained earnings	6,221			6,173
Total common shareholder's equity	8,968			8,913
Preferred and preference stock	1,395			1,045
Total equity	10,363			9,958
Total liabilities and equity	$	41,605		$	40,315

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



Consolidated Statements of Cash Flows	Southern California Edison Company



	Three months ended March 31,
(in millions, unaudited)	2012			2011
Cash flows from operating activities:
Net income	$	201		$	236
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	389			344
Regulatory impacts of net nuclear decommissioning trust earnings	77			41
Other amortization	20			28
Stock-based compensation	4			4
Deferred income taxes and investment tax credits	156			257
Proceeds from U.S. treasury grants	29			—
Changes in operating assets and liabilities:
Receivables	90			90
Inventory	11			4
Margin and collateral deposits – net of collateral received	(1		)	2
Prepaid taxes	(1		)	(57		)
Other current assets	19			(4		)
Accounts payable	(53		)	(88		)
Accrued taxes	62			2
Other current liabilities	(185		)	(244		)
Derivative assets and liabilities – net	336			102
Regulatory assets and liabilities – net	(317		)	(42		)
Other assets	(10		)	(6		)
Other liabilities	(52		)	3
Net cash provided by operating activities	775			672
Cash flows from financing activities:
Long-term debt issued	395			—
Long-term debt issuance costs	(4		)	—
Long-term debt repaid	(1		)	(1		)
Preference stock issued – net	345			123
Short-term debt financing – net	(89		)	200
Settlements of stock-based compensation – net	(15		)	(4		)
Dividends paid	(131		)	(128		)
Net cash provided by financing activities	500			190
Cash flows from investing activities:
Capital expenditures	(1,189		)	(1,022		)
Proceeds from sale of nuclear decommissioning trust investments	602			622
Purchases of nuclear decommissioning trust investments and other	(684		)	(669		)
Customer advances for construction and other investments	2			3
Net cash used by investing activities	(1,269		)	(1,066		)
Net increase (decrease) in cash and cash equivalents	6			(204		)
Cash and cash equivalents, beginning of period	57			257
Cash and cash equivalents, end of period	$	63		$	53

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

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. SCE is a wholly-owned subsidiary of Edison International.

Basis of Presentation

SCE's significant accounting policies were described in Note 1 of "SCE 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 $30 million and $21 million 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.

SCE temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. SCE reclassified $175 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.

Inventory

Inventory is stated at the lower of cost or market, cost being determined by the average cost method for fuel and materials and supplies. Inventory consisted of the following:



(in millions)	March 31, 2012		December 31, 2011
Fuel	$	19	$	24
Materials and supplies, spare parts	321		326
Total inventory	$	340	$	350

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. SCE 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. SCE 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. SCE 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 SCE
(in millions)	Common Stock		Additional Paid-in Capital			Accumulated Other Comprehensive Loss			Retained Earnings			Preferred and Preference Stock		Total Equity
Balance at December 31, 2011	$	2,168	$	596		$	(24	)	$	6,173		$	1,045	$	9,958
Net income	—		—			—			201			—		201
Other comprehensive income	—		—			3			—			—		3
Dividends declared on common stock	—		—			—			(116		)	—		(116		)
Dividends declared on preferred and preference stock	—		—			—			(19		)	—		(19		)
Stock-based compensation and other	—		6			—			(21		)	—		(15		)
Noncash stock-based compensation and other	—		3			—			3			—		6
Issuance of preference stock	—		(5		)	—			—			350		345
Balance at March 31, 2012	$	2,168	$	600		$	(21	)	$	6,221		$	1,395	$	10,363

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



	Equity Attributable to SCE
(in millions)	Common Stock		Additional Paid-in Capital			Accumulated Other Comprehensive Loss			Retained Earnings			Preferred and Preference Stock		Total Equity
Balance at December 31, 2010	$	2,168	$	572		$	(25	)	$	5,572		$	920	$	9,207
Net income	—		—			—			236			—		236
Other comprehensive income	—		—			1			—			—		1
Dividends declared on common stock	—		—			—			(115		)	—		(115		)
Dividends declared on preferred and preference stock	—		—			—			(14		)	—		(14		)
Stock-based compensation and other	—		1			—			(5		)	—		(4		)
Noncash stock-based compensation and other	—		4			—			(1		)	—		3
Issuance of preference stock	—		(2		)	—			—			125		123
Balance at March 31, 2011	$	2,168	$	575		$	(24	)	$	5,673		$	1,045	$	9,437

Note 3. Variable Interest Entities

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has 16 power purchase agreements ("PPAs") that have variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to fuel the plants and 10 contracts with qualifying facilities ("QFs") that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. In general, because payments for capacity are the primary source of income, the most significant economic activity for 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	$	30	$	—	$	—		$	—		$	30
Derivative contracts:
Electricity	—		—		2			—			2
Natural gas	—		4		—			(4		)	—
CRRs	—		—		101						101
Tolling	—		—		13			—			13
Subtotal of derivative contracts	—		4		116			(4		)	116
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	2,645		1,264		116			(4		)	4,021
Liabilities at Fair Value
Derivative contracts:
Electricity	—		3		83			(4		)	82
Natural gas	—		258		48			(81		)	225
Tolling	—		—		1,082			—			1,082
Subtotal of derivative contracts	—		261		1,213			(85		)	1,389
Total liabilities	—		261		1,213			(85		)	1,389
Net assets (liabilities)	$	2,645	$	1,003	$	(1,097	)	$	81		$	2,632



	December 31, 2011
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral¹			Total
Assets at Fair Value
Money market funds²	$	21	$	—	$	—		$	—		$	21
Derivative contracts:
Electricity	—		—		1			—			1
Natural gas	—		5		—			(3		)	2
CRRs	—		—		122			—			122
Tolling	—		—		10			—			10
Subtotal of derivative contracts	—		5		133			(3		)	135
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	2,361		1,240		133			(3		)	3,731
Liabilities at Fair Value
Derivative contracts:
Electricity	—		5		65			(2		)	68
Natural gas	—		234		23			(53		)	204
Tolling	—		—		799			—			799
Subtotal of derivative contracts	—		239		887			(55		)	1,071
Total liabilities	—		239		887			(55		)	1,071
Net assets (liabilities)	$	2,361	$	1,001	$	(754	)	$	52		$	2,660


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 on SCE'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	$	(754	)	$	6
Total realized/unrealized (losses), net:
Included in regulatory assets¹	(356		)	(134		)
Purchases	21			—
Settlements	(8		)	1
Transfers into Level 3	—			—
Transfers out of Level 3	—			—
Fair value of net liabilities at end of period	$	(1,097	)	$	(127	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period	$	(351	)	$	(133	)


¹	Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.

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 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 and over-the-counter derivatives. 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)							Significant	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	—			7			Discounted cash flow	Power prices	$2.10 – $33.90 ($20.70)

Gas Options	—			48			Option model	Volatility of gas prices	26% – 48% (41%)
CRRs	101			—			Market simulation model	Load forecast	7,645 MW – 26,334 MW
								Power prices	$(46.19) – $240.30
								Gas prices	$3.79 – $9.32
Tolling	13			1,082			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	(10		)	(10		)
Total derivative contracts	$	116		$	1,213

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 SCE is 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 SCE is the buyer relative to the contract price will increase (decrease) the fair value.

CRRs

Where SCE is the buyer, generally increases (decreases) in forecasted load in isolation would result in increases (decreases) to the fair value. In general, an increase (decrease) 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	$	8,827	$	10,095	$	8,431	$	10,129

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

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.

Note 6. Derivative Instruments and Hedging Activities

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 Liabilities
(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

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.

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with 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. SCE nets counterparty receivables and payables where balances exist under master netting agreements. SCE 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 counterparties:



(in millions)	March 31, 2012		December 31, 2011
Collateral provided to counterparties:
Offset against derivative liabilities	$	81	$	51
Reflected in other current assets	20		17

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 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		%

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. This included 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 adjustment and filed a protest with the IRS in the first quarter of 2011.

Note 8. Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

SCE made contributions of $2 million during the three months ended March 31, 2012 and expects to make $261 million of additional contributions during the remainder of 2012. SCE's 2012 annual contributions made to most of its pension plans are anticipated to be recovered through CPUC-approved regulatory mechanisms, pending the 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	$	37		$	38
Interest cost	45			47
Expected return on plan assets	(55		)	(56		)
Amortization of prior service cost	1			2
Amortization of net loss	15			4
Expense under accounting standards	$	43		$	35
Regulatory adjustment (deferred)	25			(6		)
Total expense recognized	$	68		$	29

Postretirement Benefits Other Than Pensions

SCE made contributions of $5 million during the three months ended March 31, 2012 and expects to make $57 million of additional contributions during the remainder of 2012. SCE's 2012 annual contributions are anticipated to be recovered through CPUC-approved regulatory mechanisms, pending the 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	$	12		$	10
Interest cost	28			31
Expected return on plan assets	(27		)	(27		)
Amortization of prior service credit	(9		)	(9		)
Amortization of net loss	11			9
Total expense	$	15		$	14

Transfer of Certain Postretirement Benefits to Edison International

In March 2012, Edison International agreed to assume the liabilities for active employees of SCE and its subsidiaries under the specified plans related to deferred compensation and executive post retirement benefits. SCE is obligated to reimburse Edison International upon settlement of liabilities on an after tax basis. Included in the consolidated balance sheet at March 31, 2012 was $111 million related to this obligation.

Note 9. Commitments and Contingencies

Indemnities

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 Indemnities

SCE 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. SCE's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties. SCE 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, SCE is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. SCE believes the outcome of these other proceedings, individually and in the aggregate, will not materially affect its results of operations or liquidity.

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

SCE 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. SCE 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, SCE 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, SCE's recorded estimated minimum liability to remediate its 25 identified material sites (sites in which the upper end of the range of the costs is at least $1 million) and 33 identified immaterial sites was $43 million (which includes $12 million related to San Onofre) and $3 million, respectively. Of the $46 million total environmental remediation liability, $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. SCE'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 SCE 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 SCE'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. SCE 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. The upper limit of this range of costs was estimated using assumptions least favorable to SCE 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, SCE 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

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. Supplemental Cash Flows Information

SCE'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	$	151		$	149
Tax payments (refunds) – net	(1		)	(102		)
Dividends declared but not paid:
Preferred and preference stock	$	10		$	10

Accrued capital expenditures at March 31, 2012 and 2011 were $412 million and $423 million, respectively. Accrued capital expenditures will be included as an investing activity in the consolidated statements of cash flow in the period paid.

Note 12. Preferred and Preference Stock

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 13. 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	1,139		836
Unamortized investments - 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	6,124		5,815
Total Regulatory Assets	$	6,816	$	6,309

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 14. 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 15. 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 other income	$	31	$	38
Other expenses:
Civic, political and related activities and donations	$	6	$	7
Other	3		6
Total other expenses	$	9	$	13

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 SCE's current expectations and projections about future events based on SCE'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 SCE 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 SCE, include, but are not limited to:


•	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;


•	environmental laws and regulations, both at the 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;


•	cost of capital and the ability to borrow funds and access to capital markets on reasonable terms;


•	the 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 SCE'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 SCE's business. Forward-looking statements speak only as of the date they are made and SCE is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by SCE 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 SCE 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 SCE's MD&A for the calendar year 2011 (the "year-ended 2011 MD&A"), which was included in the 2011 Form 10-K.

MANAGEMENT OVERVIEW

Highlights of Operating Results



	Three months ended March 31,
(in millions)	2012		2011		Change
Core earnings	$	182	$	222	$	(40	)
Non-core items	—		—		—
Net income available for common stock	$	182	$	222	$	(40	)

SCE's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings for financial planning and for analysis of performance. Core earnings are also used when communicating with analysts and investors regarding SCE's earnings results to facilitate comparisons of the performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to SCE less income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: settlement of certain tax, regulatory or legal matters or proceedings.

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.

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.

Environmental Developments

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

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 "Management 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 "Management Overview—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 "Management Overview—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 "SCE 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 "SCE 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 "Liquidity and Capital Resources—Workers Compensation Self-Insurance Fund" in the year ended 2011 MD&A.

Historical Consolidated 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 "SCE 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 "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 "SCE 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 "SCE 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 "SCE 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 "SCE 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.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

For a discussion of SCE'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 "SCE Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to this item is included in the MD&A under the heading "Market Risk Exposures" and is incorporated herein by reference.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SCE's management, under the supervision and with the participation of the company's President and Chief Financial Officer, has evaluated the effectiveness of SCE'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 President and Chief Financial Officer concluded that, as of the end of the period, SCE's disclosure and procedures were effective.

Change in Internal Control Over Financial Reporting

There were no changes in SCE's internal control over financial reporting during the period to which this report relates that have materially affected, or are reasonably likely to materially affect, SCE's internal control over financial reporting.

Jointly Owned Utility Plant

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 6. EXHIBITS



Exhibit Number		Description

3.1		Certificate of Determination of Series of Preferences of the Series E Preference Stock effective January 12, 2012 (File No. 1-2313, filed as Exhibit 4 to Southern California Edison Company's Form 8-K dated January 11, 2012 and filed January 13, 2012)*

3.2		Certificate of Increase in Authorized Shares of Series E Preference Stock effective January 31, 2012 (File No. 1-2313, filed as Exhibit 4.1 to Southern California Edison Company's Form 8-K dated January 30, 2012 and filed February 1, 2012)*

10.1**		Edison International 2012 Executive Annual Incentives Program (File No.1-9936, filed as Exhibit 10.1 to the Edison International Form 10-Q for the quarter ended March 31, 2012)*

10.2**		Edison International 2012 Long-Term Incentive Terms and Conditions (File No.1-9936, filed as Exhibit 10.2 to the Edison International Form 10-Q for the quarter ended March 31, 2012)*

10.3**		Edison International Executive Incentive Compensation Plan (File No.1-9936, filed as Exhibit 10.3 to the Edison International Form 10-Q for the quarter ended March 31, 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 Southern California Edison Company 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 tagged as blocks of text

_____________________________

* Incorporated by reference pursuant to Rule 12b-32.

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

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

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.



	SOUTHERN CALIFORNIA EDISON COMPANY

	By:	/s/ Chris C. Dominski
		Chris C. Dominski Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)

Date: May 2, 2012

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SOUTHERN CALIFORNIA EDISON (SCE-PN) 10-Q2012 Q1 Quarterly report

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