SOUTHERN CALIFORNIA EDISON (SCE-PN) 10-Q 2011 Q1 Quarterly report

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

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2011
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from                         to

Commission File Number 1-2313

SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)

California	95-1240335
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2244 Walnut Grove Avenue (P. O. Box 800) Rosemead, California	91770
(Address of principal executive offices)	(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 ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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 filero Accelerated filero Non-accelerated filerý
(Do not check if a smaller
reporting company) Smaller reporting companyo

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

Class	Outstanding at April 28, 2011
Common Stock, no par value	434,888,104

TABLE OF CONTENTS

GLOSSARY				iii
PART 1. 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			6
	Note 4. Fair Value Measurements			7
	Note 5. Debt and Credit Agreements			11
	Note 6. Derivative Instruments and Hedging Activities			12
	Note 7. Income Taxes			14
	Note 8. Compensation and Benefit Plans			15
	Note 9. Commitments and Contingencies			18
	Note 10. Regulatory and Environmental Developments			21
	Note 11. Supplemental Cash Flows Information			21
	Note 12. Preferred and Preference Stock			22
	Note 13. Regulatory Assets and Liabilities			22
	Note 14. Other Investments			22
	Note 15. Other Income and Expenses			23
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				24
FORWARD-LOOKING STATEMENTS				24
MANAGEMENT OVERVIEW				25
	Highlights of Operating Results			25
	Capital Program			26
	2012 CPUC General Rate Case			26
	Nuclear Industry and Regulatory Response to Events in Japan			26
	Environmental Developments			26
RESULTS OF OPERATIONS				26
	Electric Utility Results of Operations			27
		Utility Earning Activities		27
			2011 vs. 2010	27

i

		Utility Cost-Recovery Activities		28
			2011 vs. 2010	28
		Supplemental Operating Revenue Information		28
		Income Taxes		29
LIQUIDITY AND CAPITAL RESOURCES				29
	Available Liquidity			29
		Debt Covenant		29
	Dividend Restrictions			30
	Margin and Collateral Deposits			30
		Derivative Instruments and Power Procurement Contracts		30
		Workers Compensation Self-Insurance Fund		30
	Historical Consolidated Cash Flows			30
		Condensed Consolidated Statement of Cash Flows		31
			Net Cash Provided by Operating Activities	31
			Net Cash Provided by Financing Activities	31
			Net Cash Used by Investing Activities	31
	Contractual Obligations and Contingencies			31
		Contractual Obligations		31
		Contingencies		32
			Environmental Remediation	32
MARKET RISK EXPOSURES				32
	Commodity Price Risk			32
	Credit Risk			32
CRITICAL ACCOUNTING ESTIMATES AND POLICIES				33
NEW ACCOUNTING GUIDANCE				33
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				33
ITEM 4. CONTROLS AND PROCEDURES				33
	Disclosure Controls and Procedures			33
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS				33
	California Coastal Commission Potential Environmental Proceeding			33
ITEM 6. EXHIBITS				34
SIGNATURE				35

ii

GLOSSARY

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

2010 Form 10-K	SCE's Annual Report on Form 10-K for the year-ended December 31, 2010
2010 Tax Relief Act	Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
AFUDC	allowance for funds used during construction
APS	Arizona Public Service Company
ARO(s)	asset retirement obligation(s)
Bcf	Billion cubic feet
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 Technical 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
NOx	nitrogen oxide
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

iii

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
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
US EPA	U.S. Environmental Protection Agency
VIE(s)	variable interest entity(ies)
year-ended 2010 MD&A	Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in the 2010 Form 10-K

iv

Part 1. Financial information

ITEM 1. FINANCIAL STATEMENTS

Consolidated Statements of Income Southern California Edison Company

	Three months ended March 31,
(in millions, unaudited)	2011			2010
Operating revenue	$	2,232		$	2,159
Fuel		76			81
Purchased power		508			608
Operation and maintenance		784			713
Depreciation, decommissioning and amortization		344			309
Property and other taxes		77			68
Total operating expenses		1,789			1,779
Operating income		443			380
Interest income		2			1
Other income		38			34
Interest expense – net of amounts capitalized		(111	)		(99	)
Other expenses		(13	)		(10	)
Income before income taxes		359			306
Income tax expense		123			129
Net income		236			177
Dividends on preferred and preference stock		14			13
Net income available for common stock	$	222		$	164

Consolidated Statements of Comprehensive Income

			Three months ended March 31,
(in millions, unaudited)			2011		2010
Net income			$	236	$	177
Other comprehensive income, net of tax:
	Pension and postretirement benefits other than pensions:
		Amortization of net loss included in net income		1		1
Comprehensive income			$	237	$	178

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

1

Consolidated Balance Sheets Southern California Edison Company

(in millions, unaudited)	March 31, 2011		December 31, 2010
ASSETS
Cash and cash equivalents	$	53	$	257
Receivables, less allowances of $87 and $85 for uncollectible accounts at respective dates		625		715
Accrued unbilled revenue		410		442
Inventory		328		332
Prepaid taxes		225		168
Derivative assets		77		87
Regulatory assets		407		378
Other current assets		101		81
Total current assets		2,226		2,460
Nuclear decommissioning trusts		3,619		3,480
Other investments		76		68
Total investments		3,695		3,548
Utility property, plant and equipment, less accumulated depreciation of $6,488 and $6,319 at respective dates		25,276		24,778
Nonutility property, plant and equipment, less accumulated depreciation of $101 and $100 at respective dates		75		71
Total property, plant and equipment		25,351		24,849
Derivative assets		289		367
Regulatory assets		4,450		4,347
Other long-term assets		333		335
Total long-term assets		5,072		5,049
Total assets	$	36,344	$	35,906

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

2

Consolidated Balance Sheets Southern California Edison Company

(in millions, except share amounts, unaudited)	March 31, 2011			December 31, 2010
LIABILITIES AND EQUITY
Short-term debt	$	200		$	—
Accounts payable		958			1,271
Accrued taxes		47			45
Accrued interest		118			169
Customer deposits		211			217
Derivative liabilities		215			212
Regulatory liabilities		778			738
Other current liabilities		482			663
Total current liabilities		3,009			3,315
Long-term debt		7,627			7,627
Deferred income taxes		5,096			4,829
Deferred investment tax credits		117			118
Customer advances		112			112
Derivative liabilities		461			449
Pensions and benefits		1,851			1,838
Asset retirement obligations		2,508			2,507
Regulatory liabilities		4,733			4,524
Other deferred credits and other long-term liabilities		1,393			1,380
Total deferred credits and other liabilities		16,271			15,757
Total liabilities		26,907			26,699
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		575			572
Accumulated other comprehensive loss		(24	)		(25	)
Retained earnings		5,673			5,572
Total common shareholder's equity		8,392			8,287
Preferred and preference stock		1,045			920
Total equity		9,437			9,207
Total liabilities and equity	$	36,344		$	35,906

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

3

Consolidated Statements of Cash Flows Southern California Edison Company

			Three months ended March 31,
(in millions, unaudited)			2011			2010
Cash flows from operating activities:
Net income			$	236		$	177
Adjustments to reconcile to net cash provided by operating activities:
	Depreciation, decommissioning and amortization			344			309
	Regulatory impacts of net nuclear decommissioning trust earnings (reflected			41			38
		in accumulated depreciation)
	Other amortization			28			21
	Stock-based compensation			4			4
	Deferred income taxes and investment tax credits			257			189
Changes in operating assets and liabilities:
	Receivables			90			62
	Inventory			4			1
	Margin and collateral deposits – net of collateral received			2			(2	)
	Prepaid taxes			(57	)		(104	)
	Other current assets			(4	)		(47	)
	Accounts payable			(88	)		(158	)
	Accrued taxes			2			29
	Other current liabilities			(244	)		(153	)
	Derivative assets and liabilities – net			102			577
	Regulatory assets and liabilities – net			(42	)		(636	)
	Other assets			(6	)		(14	)
	Other liabilities			3			20
Net cash provided by operating activities				672			313
Cash flows from financing activities:
Long-term debt issued				—			494
Long-term debt issuance costs				—			(5	)
Long-term debt repaid				(1	)		(252	)
Preference stock issued				123			—
Short-term debt financing – net				200			180
Settlements of stock-based compensation – net				(4	)		1
Dividends paid				(128	)		(113	)
Net cash provided by financing activities				190			305
Cash flows from investing activities:
Capital expenditures				(1,022	)		(867	)
Proceeds from sale of nuclear decommissioning trust investments				622			286
Purchases of nuclear decommissioning trust investments and other				(669	)		(335	)
Customer advances for construction and other investments				3			(6	)
Effect of deconsolidation of variable interest entities				—			(92	)
Net cash used by investing activities				(1,066	)		(1,014	)
Net decrease in cash and cash equivalents				(204	)		(396	)
Cash and cash equivalents, beginning of period				257			462
Cash and cash equivalents, end of period			$	53		$	66

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

4

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 2010 Form 10-K. SCE follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2011, discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2010 Form 10-K.

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three month period ended March 31, 2011 are not necessarily indicative of the operating results for the full year.

The December 31, 2010 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $30 million and $243 million at March 31, 2011 and December 31, 2010, respectively. Generally, the carrying value of cash equivalents equals the fair value, as all investments have maturities of three months or less.

SCE temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. SCE reclassified $206 million and $196 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at March 31, 2011 and December 31, 2010, 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.

(in millions)	March 31, 2011		December 31, 2010
Fuel	$	20	$	21
Materials and supplies, spare parts		308		311
Total inventory	$	328	$	332

New Accounting Guidance

Accounting Guidance Adopted in 2011

Fair Value Measurements and Disclosures

The FASB issued an accounting standards update modifying the disclosure requirements related to fair value measurements. Under these requirements, purchases and settlements for Level 3 fair value

5

measurements are presented on a gross basis, rather than net. SCE adopted this guidance effective January 1, 2011.

Note 2. Consolidated Statements of Changes in Equity

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 Income (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

The following table provides the changes in equity for the three months ended March 31, 2010.

	Equity Attributable to SCE
(in millions)	Common Stock		Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Preferred and Preference Stock		Noncontrolling Interest			Total Equity
Balance at December 31, 2009	$	2,168	$	551	$	(19	)	$	4,746		$	920	$	349		$	8,715
Net income		—		—		—			177			—		—			177
Other comprehensive income		—		—		1			—			—		—			1
Deconsolidation of variable interest entities		—		—		—			—			—		(349	)		(349	)
Dividends declared on preferred and preference stock		—		—		—			(13	)		—		—			(13	)
Stock-based compensation and other		—		2		—			(1	)		—		—			1
Noncash stock-based compensation and other		—		4		—			(4	)		—		—			—
Balance at March 31, 2010	$	2,168	$	557	$	(18	)	$	4,905		$	920	$	—		$	8,532

Note 3. Variable Interest Entities

A variable interest entity ("VIE") is defined as a legal entity whose equity owners do not have sufficient equity at risk, or, as a group, the holders of the equity investment at risk lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE. Commercial and operating activities are generally the factors that most significantly impact the economic performance of VIEs in which SCE has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.

6

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has 16 power purchase agreements ("PPAs") that are considered variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to operate the plants and 10 contracts with QFs that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. In general, because payments for capacity are the primary source of income, the most significant economic activity for SCE's VIEs is the operation and maintenance of the power plants.

As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts. These are accounted for at fair value. Under these contracts, SCE recovers the costs incurred under its approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 9, so 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, 2011 and the amounts that SCE paid to these projects were $86 million and $125 million for the three months ended March 31, 2011 and 2010, respectively. These amounts are recovered in customer rates.

Note 4. Fair Value Measurements

Recurring Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value of an asset or liability should consider assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk.

SCE categorizes financial assets and liabilities into a fair value hierarchy based on valuation inputs used to derive fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

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

		As of March 31, 2011
(in millions)		Level 1		Level 2		Level 3			Collateral			Total
Assets at Fair Value
Money market funds1		$	30	$	—	$	—		$	—		$	30
Derivative contracts2:
	Electricity		—		1		46			—			47
	Natural gas		—		66		8			—			74
	CRRs		—		—		123			—			123
	Tolling		—		—		122			—			122
Subtotal of derivative contracts			—		67		299			—			366
Long-term disability plan			9		—		—			—			9
Nuclear decommissioning trusts:
	Stocks3		2,068		—		—			—			2,068
	Municipal bonds		—		772		—			—			772
	Corporate bonds4		—		320		—			—			320
	U.S. government and agency securities		251		103		—			—			354
	Short-term investments, primarily cash equivalents5		—		80		—			—			80
	Sub-total of nuclear decommissioning trusts		2,319		1,275		—			—			3,594
Total assets6			2,358		1,342		299			—			3,999
Liabilities at Fair Value
Derivative contracts2:
	Electricity		—		—		45			—			45
	Natural gas		—		254		7			(4	)		257
	Tolling		—		—		374			—			374
Subtotal of derivative contracts			—		254		426			(4	)		676
Total liabilities			—		254		426			(4	)		676
Net assets		$	2,358	$	1,088	$	(127	)	$	4		$	3,323

8

		As of December 31, 2010
(in millions)		Level 1		Level 2		Level 3		Collateral			Total
Assets at Fair Value
Money market funds1		$	243	$	—	$	—	$	—		$	243
Derivative contracts2:
	Electricity		—		—		119		—			119
	Natural gas		—		69		11		—			80
	CRRs		—		—		137		—			137
	Tolling		—		—		118		—			118
Subtotal of derivative contracts			—		69		385		—			454
Long-term disability plan			9		—		—		—			9
Nuclear decommissioning trusts
	Stocks3		2,029		—		—		—			2,029
	Municipal bonds		—		790		—		—			790
	Corporate bonds4		—		346		—		—			346
	U.S. government and agency securities		215		73		—		—			288
	Short-term investments, primarily cash equivalents5		1		31		—		—			32
	Sub-total of nuclear decommissioning trusts		2,245		1,240		—		—			3,485
Total assets6			2,497		1,309		385		—			4,191
Liabilities at Fair Value
Derivative contracts2:
	Electricity		—		1		24		—			25
	Natural gas		—		285		11		(4	)		292
	Tolling		—		—		344		—			344
Subtotal of derivative contracts			—		286		379		(4	)		661
Total liabilities			—		286		379		(4	)		661
Net assets (liabilities)		$	2,497	$	1,023	$	6	$	4		$	3,530

¹

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

²

Represents the netting of assets and liabilities under master netting agreements and cash collateral across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.

³

Approximately 68% and 67% of the equity investments were located in the United States at March 31, 2011 and December 31, 2010, respectively.

⁴

Corporate bonds are diversified, and included $25 million and $27 million at March 31, 2011 and December 31, 2010, respectively, for collateralized mortgage obligations and other asset backed securities.

⁵

Excludes net receivables of $25 million and net liabilities of $5 million at March 31, 2011 and December 31, 2010, respectively, of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases.

⁶

Excludes $31 million at both March 31, 2011 and December 31, 2010, respectively, of cash surrender value of life insurance investments for deferred compensation.

9

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

		Three months ended March 31,
(in millions)		2011			2010
Fair value of derivative contracts, net assets (liabilities) at beginning of period		$	6		$	(111	)
Total realized/unrealized losses, net:
	Included in regulatory assets and liabilities1		(134	)		(487	)
Purchases			—			2
Settlements			1			—
Transfers into Level 3			—			—
Transfers out of Level 3			—			—
Fair value of derivative contracts, net liabilities at end of period		$	(127	)	$	(596	)
Change during the period in unrealized losses related to assets and liabilities held at the end of period		$	(133	)	$	(468	)

¹

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

SCE determines the fair value for transfers in and transfers out of each level at the end of each reporting period. There were no significant transfers between levels during 2011 and 2010.

Valuation Techniques Used to Determine Fair Value

Level 1

Includes assets and liabilities where fair value is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. Financial assets and liabilities classified as Level 1 include exchange-traded equity securities, exchange traded derivatives, U.S. treasury securities and money market funds.

Level 2

Pricing inputs include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument. Financial assets and liabilities utilizing Level 2 inputs include fixed-income securities and over-the-counter derivatives.

Derivative contracts that are over-the-counter traded are valued using pricing models to determine the net present value of estimated future cash flows and are generally classified as Level 2. Inputs to the pricing models include forward published or posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar instruments and discount rates. A primary source that best represents traded activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity. Broker quotes are incorporated when corroborated with other information which may include a combination of prices from exchanges, other brokers and comparison to executed trades.

Level 3

Includes financial assets and liabilities where fair value is determined using techniques that require significant unobservable inputs. Over-the-counter options, bilateral contracts, capacity contracts, QF contracts, derivative contracts that trade infrequently (such as congestion revenue rights ("CRRs") in the California market and over-the-counter derivatives at illiquid locations), long-term power agreements, and derivative contracts with counterparties that have significant nonperformance risks are generally valued using pricing models that incorporate unobservable inputs and are classified as Level 3. Assumptions are made in order to value derivative contracts in which observable inputs are not available. In circumstances where SCE cannot verify fair value with observable market transactions, it is possible that a different

10

valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, SCE continues to assess valuation methodologies used to determine fair value.

For derivative contracts that trade infrequently (illiquid financial transmission rights and CRRs), changes in fair value are based on models forecasting the value of those contracts. The models' inputs are reviewed and the fair value is adjusted when it is concluded that a change in inputs would result in a new valuation that better reflects the fair value of those derivative contracts. For illiquid long-term power agreements, fair value is based upon the discounting of future electricity and natural gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. The fair value of the majority of SCE's derivatives that are classified as Level 3 is determined using uncorroborated non-binding broker quotes and models which may require SCE to extrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for reasonableness.

Nonperformance Risk

The fair value of the derivative assets and liabilities are adjusted for nonperformance risk. To assess nonperformance risks, SCE considers the probability of and the estimated loss incurred if a party to the transaction were to default. SCE also considers collateral, netting agreements, guarantees and other forms of credit support when assessing nonperformance. The nonperformance risk adjustment represented an insignificant amount at both March 31, 2011 and December 31, 2010.

Nuclear Decommissioning Trusts

SCE's nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed-income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed-income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information.

Fair Value of Long-Term Debt Recorded at Carrying Value

The carrying amounts and fair values of long-term debt are:

	March 31, 2011				December 31, 2010
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	7,627	$	8,079	$	7,627	$	8,285

Fair values of long-term debt are based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes of new issue prices and relevant credit information.

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

Note 5. Debt and Credit Agreements

Credit Agreements

At March 31, 2011, SCE's outstanding short-term debt was $200 million at a weighted-average interest rate of 0.35%. This short-term debt was supported by a $2.4 billion credit facility. At December 31, 2010, there was no outstanding short-term debt. At March 31, 2011, letters of credit issued under SCE's credit facilities aggregated $73 million and are scheduled to expire in twelve months or less.

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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 ratepayer exposure to variability in market prices related to SCE's power and gas activities. As part of this program, SCE enters into energy options, swaps, forward arrangements, tolling arrangements and CRRs. These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans. SCE recovers its related hedging costs through the ERRA balancing account, and as a result, exposure to commodity price risk is not expected to impact earnings, but may impact cash flows.

SCE's electricity price exposure arises from electricity purchased from the California wholesale market as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities, power purchase agreements and CDWR contracts allocated to SCE.

SCE's natural gas price exposure arises from natural gas purchased for generation at the Mountainview power plant and peaker plants, QF contracts where pricing is based on a monthly natural gas index and power purchase agreements in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.

Notional Volumes of Derivative Instruments

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

		Economic Hedges
Commodity	Unit of Measure	March 31, 2011		December 31, 2010
Electricity options, swaps and forwards	GWh		32,795		32,138
Natural gas options, swaps and forwards	Bcf		208		250
Congestion revenue rights	GWh		167,668		181,291
Tolling arrangements	GWh		113,541		114,599

Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at March 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	$	85		$	302		$	387		$	225		$	475		$	700		$	313
Netting and collateral		(8	)		(13	)		(21	)		(10	)		(14	)		(24	)		(3	)
Total	$	77		$	289		$	366		$	215		$	461		$	676		$	310

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The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2010:

	Derivative Assets						Derivative Liabilities
(in millions)	Short- Term		Long- Term		Subtotal		Short- Term			Long- Term		Subtotal			Net Liability
Non-trading activities
Economic hedges	$	87	$	367	$	454	$	216		$	449	$	665		$	211
Netting and collateral		—		—		—		(4	)		—		(4	)		(4	)
Total	$	87	$	367	$	454	$	212		$	449	$	661		$	207

Income Statement Impact of Derivative Instruments

SCE recognizes realized gains and losses on derivative instruments as purchased-power expense and expects to recover these costs from ratepayers. As a result, realized gains and losses are not reflected in earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore are also not reflected in earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.

The following table summarizes the components of economic hedging activity:

	Three months ended March 31,
(in millions)	2011			2010
Realized losses	$	(39	)	$	(24	)
Unrealized losses		(96	)		(581	)

Contingent Features/Credit Related Exposure

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. SCE has historically provided collateral in the form of cash and/or letters of credit for the benefit of counterparties. These requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments and other factors.

Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from each of the major credit rating agencies, referred to as a "credit-risk-related contingent feature." If SCE's credit rating were to fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The aggregate fair value of all derivative liabilities with these credit-risk-related contingent features was $82 million and $67 million as of March 31, 2011 and December 31, 2010, respectively, for which SCE has posted no collateral and $4 million of collateral to its counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2011, SCE would be required to post $2 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. However, all of the contracts that SCE has entered into with counterparties are either entered into under SCE's short-term or long-term procurement plan which has been approved by the CPUC, or the contracts are approved by the CPUC before becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance are not expected to affect earnings, but may temporarily affect cash flows.

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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, 2011		December 31, 2010
Collateral provided to counterparties:
	Offset against derivative liabilities	$	4	$	4
	Reflected in other current assets		4		5

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)		2011			2010
Income before income taxes		$	359		$	306
Provision for income tax at federal statutory rate of 35%			125			107
Increase (decrease) in income tax from:
	State tax – net of federal benefit		12			9
	Health care legislation1		—			39
	Property-related and other		(14	)		(26	)
Total income tax expense		$	123		$	129
Effective tax rate			34	%		42	%

¹

During the first quarter of 2010, SCE recorded a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.

The decreased benefit provided by property-related and other items was primarily due to lower deductions for asset removal costs and internally developed software in the first quarter of 2011 compared to the respective period in 2010.

The CPUC requires flow-through ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.

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Accounting for Uncertainty in Income Taxes

Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits:

(in millions)		2011			2010
Balance at January 1,		$	329		$	482
Tax positions taken during the current year
	Increases		22			15
Tax positions taken during a prior year
	Increases		—			128
	Decreases		(6	)		(20	)
Balance at March 31,		$	345		$	605

As of March 31, 2011 and December 31, 2010, respectively, if recognized, $231 million and $225 million of the unrecognized tax benefits would impact the effective tax rate.

Edison International's federal income tax returns and its California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 are currently under review by the Franchise Tax Board. The IRS examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included a proposed adjustment to disallow a component of SCE's repair allowance deduction. Edison International disagrees with the proposed adjustment and filed a protest with the IRS in the first quarter of 2011. If sustained, the proposed disallowance would result in a federal tax payment of $90 million, including interest.

Accrued Interest and Penalties

The total amount of accrued interest and penalties related to SCE's income tax liabilities was $62 million and $61 million as of March 31, 2011 and December 31, 2010, respectively.

The net after-tax interest and penalties recognized in income tax expense was less than $1 million and $5 million for the three months ended March 31, 2011 and 2010, respectively.

Note 8. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

During the three months ended March 31, 2011, SCE made 2011 plan year contributions of $26 million and expects to make $79 million of additional contributions during the remainder of 2011. SCE's annual contributions made to most of its pension plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.

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Expense components are:

	Three months ended March 31,
(in millions)	2011			2010
Service cost	$	38		$	29
Interest cost		47			49
Expected return on plan assets		(56	)		(49	)
Amortization of prior service cost		2			2
Amortization of net loss		4			6
Expense under accounting standards		35			37
Regulatory adjustment – deferred		(6	)		(14	)
Total expense recognized	$	29		$	23

Postretirement Benefits Other Than Pensions

During the three months ended March 31, 2011, SCE made 2011 plan year contributions of $6 million and expects to make $48 million of additional contributions during the remainder of 2011. SCE's annual contributions are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.

Expense components are:

	Three months ended March 31,
(in millions)	2011			2010
Service cost	$	10		$	7
Interest cost		31			30
Expected return on plan assets		(27	)		(25	)
Amortization of prior service cost (credit)		(9	)		(9	)
Amortization of net loss		9			8
Total expense	$	14		$	11

Stock-Based Compensation

During the first quarter of 2011, Edison International granted its 2011 stock-based compensation awards to SCE employees, which included stock options, performance shares and restricted stock units.

Stock Options

The following is a summary of the status of Edison International stock options granted to SCE employees:

				Weighted-Average
	Stock Options			Exercise Price		Remaining Contractual Term (Years)		Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2010		10,064,736		$	32.86
Granted		1,750,787			37.95
Forfeited		(62,642	)		32.37
Exercised		(286,650	)		24.62
Affiliate transfers – net		106,728			32.61
Outstanding at March 31, 2011		11,572,959			33.83		6.65
Vested and expected to vest at March 31, 2011		11,301,432			33.83		6.59	$	64
Exercisable at March 31, 2011		6,666,056			33.94		5.10		45

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At March 31, 2011, there was $18 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately three years.

Performance Shares

The following is a summary of the status of Edison International nonvested performance shares:

	Equity Awards					Liability Awards
	Shares			Weighted-Average Grant Date Fair Value		Shares			Weighted-Average Fair Value
Nonvested at December 31, 2010		219,904		$	32.15		219,904		$	37.68
Granted		78,175			31.81		78,175
Forfeited		(44,788	)		54.69		(44,788	)
Affiliate transfers – net		3,097			27.15		3,097
Nonvested at March 31, 2011		256,388			28.05		256,388			25.85

The current portion of nonvested performance shares classified as liability awards is reflected in "Other current liabilities" and the long-term portion is reflected in "Pensions and benefits" on the consolidated balance sheets.

At March 31, 2011, there was $4 million (based on the March 31, 2011 fair value of performance shares classified as equity awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately two years.

Restricted Stock Units

The following is a summary of the status of Edison International nonvested restricted stock units granted to SCE employees:

	Restricted Stock Units			Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2010		385,877		$	32.90
Granted		131,039			37.95
Forfeited		(5,935	)		30.35
Paid Out		(68,149	)		55.34
Affiliate transfers – net		5,657			29.74
Nonvested at March 31, 2011		448,489			31.79

At March 31, 2011, there was $8 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $4 million in 2011, $3 million in 2012 and $1 million in 2013.

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Supplemental Data on Stock Based Compensation

		Three months ended March 31,
(in millions, except per award amounts)		2011		2010
Stock based compensation expense1		$	2	$	5
Income tax benefits related to stock compensation expense			1		2
Excess tax benefits2			2		1
Stock options
	Cash used to purchase shares to settle options		11		4
	Cash from participants to exercise stock options		7		3
	Value of options exercised		4		1
Restricted stock units
	Value of shares settled		4		—
	Tax benefits realized from settlement of awards		2		—

¹

Reflected in "Operations and maintenance" on the consolidated statements of income.

²

Reflected in "Settlements of stock based compensation—net" in the financing section of the consolidated statements of cash flows.

No performance shares were settled as of March 31, 2011 and 2010, respectively.

Note 9. Commitments and Contingencies

Third-Party Power Purchase Agreements

During the first quarter of 2011, SCE entered into a renewable energy power purchase contract which is classified as an operating lease. SCE's additional commitments under this contract are estimated to be: $29 million each year in 2012 – 2015 and $468 million for the period remaining thereafter.

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

The Mountainview power plant utilizes water from on-site groundwater wells and City of Redlands ("City") recycled water for cooling purposes. Unrelated to the operation of the plant, the groundwater contains perchlorate. The pumping of the water removes perchlorate from the aquifer beneath the plant and concentrates it in the plant's wastewater treatment "filter cake." Use of this impacted groundwater for cooling purposes was mandated by Mountainview's California Energy Commission permit. SCE has indemnified the City for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this indemnity.

Other 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

18

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

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 will not materially affect its results of operations or liquidity.

Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 against SCE, among other defendants, arising out of the coal supply agreement for Mohave. Subsequently, the Hopi Tribe was added as an additional plaintiff. As amended in April 2010, the Navajo Nation's complaint asserts claims for, among other things, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The complaint claims that the defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The complaint seeks damages of not less than $600 million, plus interest thereon, and punitive damages of not less than $1 billion. No trial date has been set for this litigation. In April 2009, in a related case filed in December 1993 against the U.S. Government, the U.S. Supreme Court found that the Navajo Nation did not have a claim for compensation. In October 2010, the Hopi Tribe settled all of its claims and the remaining parties agreed to engage in mediation. SCE cannot predict the outcome of the Navajo Nation's complaint against SCE.

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, operations and maintenance, monitoring and site closure. Unless there is a 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.

As of March 31, 2011, SCE's recorded estimated minimum liability to remediate its 24 identified material sites (sites in which the upper end of the range of costs is at least $1 million) was $52 million, of which $20 million was related to San Onofre. In addition to its identified material sites, SCE also has 33 immaterial sites for which the total minimum recorded liability was $3 million. The ultimate costs to clean up 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 these identified material sites and immaterial sites could exceed its recorded liability by up to $190 million and $7 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.

The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $28 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE recovers 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a

19

regulatory asset of $52 million at March 31, 2011 for its estimated minimum environmental cleanup costs expected to be recovered 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.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $3 million to $18 million. Recorded costs were $4 million and less than $1 million for the three months ended March 31, 2011 and 2010, respectively.

Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range for its identified sites and, 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 such estimates.

Nuclear Insurance

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

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

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $48 million per year. Insurance premiums are charged to operating expense.

Spent Nuclear Fuel

Under federal law, the Department of Energy ("DOE") is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to begin acceptance of spent nuclear fuel by January 31, 1998. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim storage for spent nuclear fuel on site sufficient for the current license period.

In January 2004, SCE, as operating agent of San Onofre, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. In June 2010, the United States Court of Federal Claims issued a decision granting SCE damages of approximately $142 million to recover costs incurred through December 31, 2005, which has been appealed by the DOE. Additional legal action would be necessary to recover damages incurred after that date. Any damages recovered would be returned to SCE ratepayers or used to offset past or future fuel decommissioning or storage costs for the benefit of ratepayers.

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Note 10. Regulatory and Environmental Developments

Environmental Developments

Greenhouse Gas Regulation

In March 2011, a California court issued an order suspending CARB's regulations implementing a California cap-and-trade program. The order would also potentially apply to other measures included in the regulations. The CARB has the right to appeal the ruling.

In April 2011, California enacted a law requiring that California utilities purchase 33% of their electricity requirements from renewable resources. The law requires the CPUC to adopt implementing regulations. The impact of the new 33% law will depend on the content of yet to be adopted implementing regulations, which remains uncertain.

Water Quality

Once-Through Cooling Issues

In March 2011, the US EPA proposed draft standards under the federal Clean Water Act which would affect cooling water intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). The regulations are expected to be finalized by July 2012. SCE is still evaluating the proposed standards but believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable without incurring material additional capital expenditures or operating costs. The required measures to comply with the proposed standards regarding entrainment are subject to the discretion of the permitting authority, and SCE is unable at this time to assess potential costs of compliance, which could be significant for San Onofre.

In addition to the proposed draft US EPA standards, the existing California once-through cooling policy may result in significant capital expenditures at San Onofre and may affect its operations. The California policy may also significantly impact SCE's ability to procure generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems, system reliability and the cost of electricity if other coastal power plants in California are forced to shut down or limit operations.

Note 11. Supplemental Cash Flows Information

SCE's supplemental cash flows information is:

			Three months ended March 31,
(in millions)			2011			2010
Cash payments (receipts) for interest and taxes:
	Interest – net of amounts capitalized		$	149		$	132
	Tax payments (refunds) – net			(102	)		2
Noncash investing and financing activities:
	Accrued capital expenditures		$	423		$	266
	Deconsolidation of variable interest entities:
		Assets other than cash	$	—		$	306
		Liabilities and noncontrolling interests		—			(398	)
	Dividends declared but not paid:
		Preferred and preference stock	$	10		$	8

21

Note 12. Preferred and Preference Stock

In March 2011, SCE issued 1,250,000 shares of 6.5% Series D preference stock (cumulative, $100 liquidation value). The Series D preference stock may not be redeemed prior to March 1, 2016. After March 1, 2016, SCE may, at its option, redeem the shares, in whole or in part. These shares are not subject to mandatory redemption.

Note 13. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)		March 31, 2011		December 31, 2010
Current:
	Regulatory balancing accounts	$	227	$	213
	Energy derivatives		173		162
	Other		7		3
			407		378
Long-term:
	Deferred income taxes – net		1,878		1,855
	Pensions and other postretirement benefits		1,094		1,097
	Unamortized generation investment – net		339		355
	Unamortized loss on reacquired debt		263		268
	Energy derivatives		261		177
	Nuclear-related ARO investment – net		167		154
	Unamortized distribution investment – net		109		105
	Regulatory balancing accounts		52		56
	Other		287		280
			4,450		4,347
Total Regulatory Assets		$	4,857	$	4,725

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	March 31, 2011		December 31, 2010
Current:
Regulatory balancing accounts	$	775	$	733
Other		3		5
		778		738
Long-term:
Costs of removal		2,648		2,623
ARO		1,251		1,099
Regulatory balancing accounts		834		802
		4,733		4,524
Total Regulatory Liabilities	$	5,511	$	5,262

Note 14. Other Investments

Nuclear Decommissioning Trusts

Future nuclear decommissioning costs of removal of nuclear assets are expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately $23 million per year included in SCE customer rates. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. If additional funds are needed for decommissioning, it is probable that the additional

22

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, 2011		December 31, 2010		March 31, 2011		December 31, 2010
Stocks	—	$	845	$	895	$	2,068	$	2,029
Municipal bonds	2049		683		706		772		790
Corporate bonds	2044		263		288		320		346
U.S. government and agency securities	2040		331		270		354		288
Short-term investments and receivables/payables	One-year		100		26		105		27
Total		$	2,222	$	2,185	$	3,619	$	3,480

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Proceeds from sales of securities (which are reinvested) were $622 million and $286 million for the three months ended March 31, 2011 and 2010, respectively. Unrealized holding gains, net of losses, were $1.4 billion and $1.3 billion at March 31, 2011 and December 31, 2010, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible.

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

(in millions)	2011			2010
Balance at January 1,	$	3,480		$	3,140
Realized gains – net		23			21
Unrealized gains – net		102			62
Other-than-temporary impairments		(9	)		(3	)
Interest, dividends, contributions and other		23			28
Balance at March 31,	$	3,619		$	3,248

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)		2011		2010
Other income:
	Equity AFUDC	$	29	$	27
	Increase in cash surrender value of life insurance policies		7		6
	Other		2		1
Total other income		$	38	$	34
Other expenses:
	Civic, political and related activities and donations	$	7	$	5
	Other		6		5
Total other expenses		$	13	$	10

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

FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect 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;

•

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

24

•

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;

•

weather conditions and natural disasters;

•

risks inherent in the development of generation projects and transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, construction, permitting, and governmental approvals; and

•

risks that competing transmission systems will be built by merchant transmission providers in SCE's territory.

Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in SCE's 2010 Form 10-K, including the "Risk Factors" section in Part I, Item 1A. Readers are urged to read this entire report, including the information incorporated by reference, as well as the 2010 Form 10-K, and carefully consider the risks, uncertainties and other factors that affect 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.

This MD&A for the three months ended March 31, 2011 discusses material changes in the consolidated financial condition, results of operations and other developments of SCE since December 31, 2010, and as compared to the three months ended March 31, 2010. This discussion presumes that the reader has read or has access to SCE's MD&A for the calendar year 2010 (the "year-ended 2010 MD&A"), which was included in the 2010 Form 10-K.

MANAGEMENT OVERVIEW

Highlights of Operating Results

		Three months ended March 31,
(in millions)		2011		2010			Change
Net Income available for common stock		$	222	$	164		$	58
Non-Core Items
	Tax impact of health care legislation		—		(39	)		39
Core Earnings		$	222	$	203		$	19

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.

The increase in core earnings of $19 million was primarily due to rate base growth. Non-core items included an after-tax earnings charge of $39 million recorded in 2010 to reverse previously recognized

25

federal tax benefits eliminated by federal health care legislation enacted in 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.

Capital Program

During the first quarter, SCE's capital investment program focused on upgrading, maintaining and expanding SCE's transmission and distribution system; maintaining and replacing generation asset equipment; and installing smart meters. Total capital expenditures (including accruals) were $765 million during the first quarter of 2011 compared to $640 million during the same period in 2010.

SCE continues to project that 2011 capital investments will be in the range of $3.9 billion to $4.4 billion and that 2011 – 2014 total capital investment spending will be in the range of $15.6 billion to $17.5 billion. Actual capital spending will be affected by regulatory approval, permitting, market and other factors as discussed further under "SCE: Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2010 MD&A.

2012 CPUC General Rate Case

As discussed in the year-ended 2010 MD&A, SCE is required to update its 2012 GRC application to reflect, among other things, the impacts of governmental and legislative actions. In April 2011, the IRS issued guidance for determining bonus depreciation enacted in the 2010 Tax Relief Act. On April 28, 2011, SCE submitted an update of its 2012 GRC application primarily to reflect bonus depreciation deductions under the 2010 Tax Relief Act, reducing its base rate revenue requirement by $38 million, $133 million and $145 million in 2012, 2013 and 2014, respectively. The decrease in base rate revenue requirement is due to a reduction in rate base from inclusion of higher deferred income taxes resulting from bonus depreciation. SCE's revised request, after considering the effects of sales growth, would result in incremental customer rate increases of $828 million, $152 million and $514 million in 2012, 2013 and 2014, respectively.

The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011. To the extent a final decision is delayed, the CPUC has authorized the establishment of a GRC memorandum account, which will make the revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.

Nuclear Industry and Regulatory Response to Events in Japan

As discussed in the 2010 Form 10-K under the heading "Nuclear Power Plant Regulation," SCE is subject to the jurisdiction of the NRC with respect to its ownership interest in San Onofre and Palo Verde. In light of the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the recent earthquake and tsunami, the NRC plans to perform additional operational and safety reviews of nuclear facilities in the United States. The lessons learned from the Japanese events and NRC reviews may impact future operations and capital requirements at United States nuclear facilities, including the operations and capital requirements of SCE's nuclear facilities.

Environmental Developments

For a discussion of environmental regulation developments regarding Greenhouse Gas Regulation and Once-Through Cooling Issues, see "SCE Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments."

RESULTS OF OPERATIONS

SCE's results of operations are derived mainly through two sources:

•

Utility earning activities – representing CPUC and FERC-authorized base rates, including the opportunity to earn the authorized return; and

•

Utility cost-recovery activities – representing CPUC-authorized balancing accounts which allow for recovery of costs incurred or provide for mechanisms to track and recover or refund differences in forecasted and actual amounts.

26

Utility earning activities include base rates that are designed to recover forecasted operation and maintenance costs, certain capital-related carrying costs, interest, taxes and a return, including the return on capital projects recovered through CPUC-authorized mechanisms outside the GRC process. Differences between authorized amounts and actual results impact earnings. Also, included in utility earning activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.

Utility cost-recovery activities include rates that provide for recovery (with no return), subject to reasonableness review, of fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs), certain operation and maintenance expenses, and depreciation expense related to certain projects.

Electric Utility Results of Operations

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, 2011								Three months ended March 31, 2010
(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated
Operating revenue		$	1,363		$	869	$	2,232		$	1,265		$	894		$	2,159
Fuel and purchased power			—			584		584			—			689			689
Operations and maintenance			528			256		784			519			194			713
Depreciation, decommissioning and amortization			317			27		344			300			9			309
Property taxes and other			75			2		77			68			—			68
Total operating expenses			920			869		1,789			887			892			1,779
Operating income			443			—		443			378			2			380
Net interest expense and other			(84	)		—		(84	)		(72	)		(2	)		(74	)
Income before income taxes			359			—		359			306			—			306
Income tax expense			123			—		123			129			—			129
Net income			236			—		236			177			—			177
Dividends on preferred and preference stock			14			—		14			13			—			13
Net income available for common stock		$	222		$	—	$	222		$	164		$	—		$	164
Core Earnings1							$	222								$	203
Non-Core Earnings:
	Tax impact of health care legislation							—									(39	)
Total SCE GAAP Earnings							$	222								$	164

¹

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

Utility Earning Activities

2011 vs. 2010

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $98 million primarily due to the following:

•

$45 million increase primarily due to a 4.35% increase in 2011 authorized revenue compared to the 2010 revenue requirement approved in the CPUC 2009 GRC decision.

27

•

$40 million increase in FERC-related revenue due to the implementation of the 2010 FERC rate case effective March 1, 2010 and construction work in progress ("CWIP") incentive earnings for the Tehachapi transmission project.

•

$15 million increase related to capital-related revenue requirements recovered through CPUC-authorized mechanisms outside of the GRC process primarily related to the steam generator replacement project and the EdisonSmartConnect™ project.

•

Higher depreciation, decommissioning and amortization expense of $17 million primarily related to increased capital expenditures, including capitalized software costs.

See "—Income Taxes" below for more information on lower income taxes during 2011 compared to the same period in 2010.

Utility Cost-Recovery Activities

2011 vs. 2010

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

•

Lower purchased power expense of $100 million related to: lower net ISO-related costs of $55 million primarily due to higher replacement power costs in 2010 related to the San Onofre Unit 2 extended outage and lower market prices in 2011; lower QF and renewable purchased power expense of $30 million primarily related to lower purchases due to expiration of a contract and lower natural gas prices; and lower bilateral energy purchase expense of $25 million primarily due to lower capacity payments as a result of expiring tolling contracts.

•

Higher operation and maintenance expense of $62 million for energy efficiency programs.

•

Higher depreciation, decommissioning and amortization expense of $18 million primarily related to the steam generator replacement project and the EdisonSmartConnect™ project.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $2.1 billion and $2.0 billion for the three months ended March 31, 2011 and 2010, respectively. The increase reflects a rate increase of $90 million and a sales volume increase of $30 million. The rate increase reflects higher system average rates for 2011 compared to the same period in 2010, primarily due to the implementation of rates authorized in the CPUC 2009 GRC decision and the 2010 FERC rate case. As a result of the CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk related to retail electricity sales (see "Item 1. Business—Overview of Ratemaking Mechanisms" in the 2010 Form 10-K).

SCE remits to CDWR and does not recognize as revenue the amounts that SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, CDWR bond-related costs and a portion of direct access exit fees. The amounts collected and remitted to CDWR were $275 million and $296 million for the three months ended March 31, 2011 and 2010, respectively. The CDWR-related rates in 2011 continue to reflect an approximately $585 million refund of operating reserves that CDWR can release as their contracts terminate. Total customer rates are expected to increase as CDWR operating reserves are fully refunded. The power contracts that CDWR allocated to SCE will terminate by the end of 2011. SCE's revenue and related purchased power expense is expected to increase as these CDWR contracts are replaced by power purchase agreements entered into by SCE.

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Income Taxes

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

		Three months ended March 31,
(in millions)		2011			2010
Income before income taxes		$	359		$	306
Provision for income tax at federal statutory rate of 35%			125			107
Increase (decrease) in income tax from:
	State tax – net of federal benefit		12			9
	Health care legislation1		—			39
	Property-related and other		(14	)		(26	)
Total income tax expense		$	123		$	129
Effective tax rate			34	%		42	%

¹

See "Management Overview—Highlights of Operating Results" for a discussion of the $39 million non-cash charge related to the federal health care legislation enacted in March 2010.

The decreased benefit provided by property-related and other items was primarily due to lower deductions for asset removal costs and internally developed software in the first quarter of 2011 compared to the respective period in 2010.

LIQUIDITY AND CAPITAL RESOURCES

SCE's ability to operate its business, complete planned capital projects, and implement its business strategy are dependent upon its cash flow and access to the capital markets to finance its activities. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, dividend payments made to Edison International, and the outcome of tax and regulatory matters.

SCE expects to fund its continuing obligations, projected capital expenditures for 2011 and dividends to Edison International through cash and equivalents on hand, operating cash flows, tax benefits and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities if additional funding and liquidity are necessary to meet operating and capital requirements.

Available Liquidity

As of March 31, 2011, SCE had approximately $53 million of cash and equivalents. SCE had two credit facilities: a $2.4 billion five-year credit facility that matures in February 2013, with four one-year options to extend by mutual consent, and a $500 million three-year credit facility that matures in March 2013.

(in millions)	Credit Facilities
Commitment	$	2,894
Outstanding borrowings supported by credit facilities		(200	)
Outstanding letters of credit		(73	)
Amount available	$	2,621

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, 2011, SCE's debt to total capitalization ratio was 0.46 to 1.

29

Dividend Restrictions

The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At March 31, 2011, SCE's 13-month weighted-average common equity component of total capitalization was 50.8% resulting in the capacity to pay $471 million in additional dividends.

During the first quarter of 2011, SCE made a $115 million dividend payment to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the actual level of capital expenditures, operating cash flows and earnings.

Margin and Collateral Deposits

Derivative Instruments and Power Procurement Contracts

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of March 31, 2011.

(in millions)
Collateral posted as of March 31, 20111	$	80
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade		53
Posted and potential collateral requirements for derivative instruments and power procurement contracts2	$	133

¹

Collateral provided to counterparties and other brokers consisted of $4 million which was offset against net derivative liabilities and $76 million (consisting of $4 million in cash reflected in "Other current assets" on the consolidated balance sheets and $72 million in letters of credit).

²

Total posted and potential collateral requirements may increase by an additional $18 million, based on SCE's forward positions as of March 31, 2011, due to adverse market price movements over the remaining life of the existing power procurement contracts using a 95% confidence level.

Workers Compensation Self-Insurance Fund

SCE is self-insured for workers compensation claims. SCE assesses workers compensation claims that have been asserted and those that have been incurred but not reported to determine the probable amount of losses that should be recorded. The Department of Industrial Relations for the State of California requires companies that are self-insured for workers compensation to post collateral (in the form of cash and/or letters of credits) based on the estimated workers' compensation liability if a company's bond rating were to fall below "B." As of March 31, 2011, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $209 million for its workers compensation self-insurance plan.

Historical Consolidated Cash Flows

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

30

Condensed Consolidated Statement of Cash Flows

	Three months ended March 31,
(in millions)	2011			2010
Net cash provided by operating activities	$	672		$	313
Net cash provided by financing activities		190			305
Net cash used by investing activities		(1,066	)		(1,014	)
Net decrease in cash and cash equivalents	$	(204	)	$	(396	)

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased $359 million in the first quarter of 2011 compared to the first quarter of 2010 primarily reflecting higher net tax receipts of $104 million in 2011 compared to 2010 related to accelerated depreciation benefits and net cash inflows related to balancing account over- and under-collections. The 2011 change was also due to the timing of cash receipts and disbursements related to working capital items.

Net Cash Provided by Financing Activities

Net cash provided by financing activities for the first quarter of 2011 was $190 million consisting of the following significant events:

•

Issued $200 million of commercial paper supported by SCE's line of credit to fund interim working capital requirements.

•

Issued $125 million of 6.5% Series D preference stock.

•

Paid a $115 million dividend to Edison International.

Net cash provided by financing activities for the first quarter of 2010 was $305 million consisting of the following significant events:

•

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

•

Issued $180 million of commercial paper supported by SCE's line of credit to fund interim working capital requirements.

•

Repaid $250 million of senior unsecured notes.

•

Paid a $100 million dividend to Edison International.

Net Cash Used by Investing Activities

Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $1.0 billion and $867 million for the three months ended March 31, 2011 and 2010, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $47 million and $49 million for the three months ended March 31, 2011 and 2010, respectively.

Contractual Obligations and Contingencies

Contractual Obligations

For a discussion of power purchase commitments, see "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Third-Party Power Purchase Agreements."

31

Contingencies

SCE has contingencies related to the Navajo Nation Litigation, nuclear 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, 2011, SCE had 24 identified material sites for remediation and recorded an estimated minimum liability of $52 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. SCE uses derivative instruments, as appropriate, to manage its market risks. For a further discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "SCE Notes to Consolidated Financial Statements—Note 6. Derivative and Hedging Activities" and "Note 4. Fair Value Measurements" and see "Market Risk Exposures—Commodity Price Risk" in the year-ended 2010 MD&A.

Commodity Price Risk

The fair value of outstanding derivative instruments used at SCE to mitigate its exposure to commodity price risk was a net liability of $310 million and $207 million at March 31, 2011 and December 31, 2010, respectively. 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 agreements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual agreements, including master netting agreements. As of March 31, 2011, the amount of balance sheet exposure as described above, by the credit ratings of SCE's counterparties, was as follows:

		March 31, 2011
(in millions)		Exposure2		Collateral			Net Exposure
S&P Credit Rating1
	A or higher	$	151	$	—		$	151
	A-		14		—			14
	Not rated3		122		(50	)		72
Total		$	287	$	(50	)	$	237

¹

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

²

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

³

The exposure in this category relates to two long-term power purchase agreements with special purpose entities for which the underlying power plants have yet to be constructed. Prior to the start date of power deliveries, SCE's recourse is limited to the collateral posted for damages associated with a contract termination. SCE's exposure is mitigated by regulatory treatment.

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The credit risk exposure set forth in the table above is composed of $7 million of net accounts receivable and $280 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

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 2010 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 this reference.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For a discussion of SCE's legal proceedings, refer to SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies" in the 2010 Form 10-K. There have been no significant developments with respect to legal proceedings specifically affecting SCE since the filing of the 2010 Form 10-K, except as follows:

California Coastal Commission Potential Environmental Proceeding

In May 2010, the California Coastal Commission issued an NOV to SCE, its contractor, and property owners related to activity on a property that was used for equipment storage related to a nearby SCE electricity line undergrounding construction project. The NOV alleged that SCE, through its contractor, violated the California Coastal Act by removing without the appropriate permits approximately one acre of vegetation from the property, which was located in a protected coastal zone within and adjacent to the City of Newport Beach, California. In late 2010, SCE tendered an indemnification claim to its contractor for liability associated with the NOV, which the contractor accepted. In the NOV, the Coastal Commission indicated an interest in negotiating a settlement of the alleged violations. The parties have reached agreement on the penalties portion of the settlement, and SCE has agreed to contribute $50,000. The parties continue to negotiate on the remaining terms of the settlement.

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ITEM 6. EXHIBITS

3.1	Certificate of Restated Articles of Incorporation of SCE, effective March 2, 2006 (File No. 1-2313, filed as Exhibit 3.1 to Southern California Edison Company's Form 10-K for the year ended December 31, 2005)*
3.2	Certificate of Determination of Preferences of the Series D Preference Stock effective March 10, 2011 (File No. 1-2313, filed as Exhibit 4 to Southern California Edison Company's Form 8-K dated March 7, 2011 and filed March 9, 2011)*
10.1	Edison International 2011 Executive Annual Incentive Program (File No. 1-9936, filed as Exhibit 10.1 to the Edison International Form 10-Q for the quarter ended March 31, 2011)*
10.2	Edison International 2011 Long-Term Incentive Terms and Conditions (File No. 1-9936 filed as Exhibit 10.2 to Edison International Form 10-Q for the quarter ended March 31, 2011)*
31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32	Statement Pursuant to 18 U.S.C. Section 1350
101**	Financial statements from the quarterly report on Form 10-Q of SCE for the quarter ended March 31, 2011, filed on May 2, 2011, formatted in XBRL: (i) the Consolidated Statements of Income; (ii) the Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; and (v) the Notes to the Consolidated Financial Statements

*

Incorporated by reference pursuant to Rule 12b-32.

**

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

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SIGNATURE

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

SOUTHERN CALIFORNIA EDISON COMPANY (Registrant)
By	/s/ Chris C. Dominski Chris C. Dominski Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)

Date: May 2, 2011

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