SOUTHERN CALIFORNIA EDISON Co - FORM 10-Q

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Table of Contents

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 June 30, 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 (State or other jurisdiction of incorporation or organization)		95-1240335 (I.R.S. Employer Identification No.)
2244 Walnut Grove Avenue (P. O. Box 800) Rosemead, California (Address of principal executive offices)		91770 (Zip Code)
(626) 302-1212 (Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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 filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No 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 August 1, 2011

Common Stock, no par value		434,888,104

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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	7
	Note 4. Fair Value Measurements	8
	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	22
	Note 12. Preferred and Preference Stock	22
	Note 13. Regulatory Assets and Liabilities	23
	Note 14. Other Investments	23
	Note 15. Other Income and Expenses	24
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		25
FORWARD-LOOKING STATEMENTS		25
MANAGEMENT OVERVIEW		26
	Highlights of Operating Results	26
	Capital Program	27
	2012 CPUC General Rate Case	27
	FERC Formula Rates	28
	Nuclear Industry and Regulatory Response to Events in Japan	28
	Environmental Developments	28

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RESULTS OF OPERATIONS				28
	Three Months Ended June 30, 2011 versus June 30, 2010			29
		*Utility Earning Activities*		29
		*Utility Cost-Recovery Activities*		30
	Six Months Ended June 30, 2011 versus June 30, 2010			30
		*Utility Earning Activities*		31
		*Utility Cost-Recovery Activities*		31
	Supplemental Operating Revenue Information			31
	Income Taxes			32
LIQUIDITY AND CAPITAL RESOURCES				32
	Available Liquidity			33
		*Debt Covenant*		33
	Dividend Restrictions			33
	Margin and Collateral Deposits			33
		*Workers Compensation Self-Insurance Fund*		34
	Historical Consolidated Cash Flows			34
		*Condensed Consolidated Statement of Cash Flows*		34
			Net Cash Provided by Operating Activities	34
			Net Cash Provided by Financing Activities	34
			Net Cash Used by Investing Activities	35
	Contractual Obligations and Contingencies			35
		*Contractual Obligations*		35
		*Contingencies*		35
			Environmental Remediation	35
MARKET RISK EXPOSURES				35
	Commodity Price Risk			35
	Credit Risk			35
CRITICAL ACCOUNTING ESTIMATES AND POLICIES				36
NEW ACCOUNTING GUIDANCE				36
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				36
ITEM 4. CONTROLS AND PROCEDURES				36
	Disclosure Controls and Procedures			36
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS				37
	California Coastal Commission Potential Environmental Proceeding			37
	Navajo Nation Litigation			37
ITEM 6. EXHIBITS				37
SIGNATURE				38

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GLOSSARY

The following terms and abbreviations appearing in the text of this report 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
NO_x		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
PBOP(s)		postretirement benefits other than pension(s)
PBR		Performance-based ratemaking
PG&E		Pacific Gas & Electric Company
PSD		Prevention of Significant Deterioration

iii

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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

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PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



Consolidated Statements of Income	Southern California Edison Company
	Three months ended June 30,						Six months ended June 30,
(in millions, unaudited)	2011			2010			2011			2010

Operating revenue	$	2,446		$	2,247		$	4,678		$	4,406

Fuel		83			94			159			175
Purchased power		649			612			1,158			1,220
Operation and maintenance		846			755			1,631			1,468
Depreciation, decommissioning and amortization		356			320			700			629
Property and other taxes		69			62			146			130

Total operating expenses		2,003			1,843			3,794			3,622

Operating income		443			404			884			784
Interest income		2			2			5			3
Other income		39			35			77			70
Interest expense		(117	)		(107	)		(228	)		(206	)
Other expenses		(13	)		(15	)		(25	)		(26	)

Income before income taxes		354			319			713			625
Income tax expense		128			5			251			134

Net income		226			314			462			491
Dividends on preferred and preference stock		15			13			29			26

Net income available for common stock	$	211		$	301		$	433		$	465

Consolidated Statements of Comprehensive Income

			Three months ended June 30,				Six months ended June 30,
(in millions, unaudited)			2011		2010		2011		2010

Net income			$	226	$	314	$	462	$	491
Other comprehensive income, net of tax:
	Pension and postretirement benefits other than pensions:
		Amortization of net loss included in net income, net of income tax expense of $1 million for the three months ended June 30, 2011, and $1 million and $1 million for both the six months ended June 30, 2011 and 2010.		1		1		2		2

Comprehensive income			$	227	$	315	$	464	$	493

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

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Consolidated Balance Sheets	Southern California Edison Company
(in millions, unaudited)	June 30, 2011		December 31, 2010

ASSETS
Cash and cash equivalents	$	42	$	257
Receivables, less allowances of $87 and $85 for uncollectible accounts at respective dates		655		715
Accrued unbilled revenue		619		442
Inventory		331		332
Prepaid taxes		61		168
Derivative assets		78		87
Regulatory assets		469		378
Other current assets		66		81

Total current assets		2,321		2,460

Nuclear decommissioning trusts		3,657		3,480
Other investments		84		68

Total investments		3,741		3,548

Utility property, plant and equipment, less accumulated depreciation of $6,486 and $6,319 at respective dates		25,847		24,778
Nonutility property, plant and equipment, less accumulated depreciation of $105 and $100 at respective dates		74		71

Total property, plant and equipment		25,921		24,849

Derivative assets		179		367
Regulatory assets		4,690		4,347
Other long-term assets		513		335

Total long-term assets		5,382		5,049





Total assets	$	37,365	$	35,906

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

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Southern California Edison Company
Consolidated Balance Sheets
(in millions, except share amounts, unaudited)	June 30, 2011			December 31, 2010

LIABILITIES AND EQUITY
Short-term debt	$	200		$	—
Accounts payable		979			1,271
Accrued taxes		26			45
Accrued interest		189			169
Customer deposits		208			217
Derivative liabilities		231			212
Regulatory liabilities		820			738
Other current liabilities		510			663

Total current liabilities		3,163			3,315

Long-term debt		8,070			7,627

Deferred income taxes		5,255			4,829
Deferred investment tax credits		129			118
Customer advances		121			112
Derivative liabilities		558			449
Pensions and benefits		1,869			1,838
Asset retirement obligations		2,546			2,507
Regulatory liabilities		4,759			4,524
Other deferred credits and other long-term liabilities		1,359			1,380

Total deferred credits and other liabilities		16,596			15,757

Total liabilities		27,829			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		581			572
Accumulated other comprehensive loss		(23	)		(25	)
Retained earnings		5,765			5,572

Total common shareholder's equity		8,491			8,287
Preferred and preference stock		1,045			920

Total equity		9,536			9,207

Total liabilities and equity	$	37,365		$	35,906

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

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Consolidated Statements of Cash Flows		Southern California Edison Company
		Six months ended June 30,
(in millions, unaudited)		2011			2010

Cash flows from operating activities:
Net income		$	462		$	491
Adjustments to reconcile to net cash provided by operating activities:
	Depreciation, decommissioning and amortization		700			629
	Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)		75			74
	Other amortization		62			50
	Stock-based compensation		8			8
	Deferred income taxes and investment tax credits		436			221
Changes in operating assets and liabilities:
	Receivables		61			(41	)
	Inventory		1			(2	)
	Margin and collateral deposits – net of collateral received		(8	)		—
	Prepaid taxes		107			(167	)
	Other current assets		(167	)		(189	)
	Accounts payable		15			(104	)
	Accrued taxes		(18	)		22
	Other current liabilities		(191	)		(75	)
	Derivative assets and liabilities – net		326			841
	Regulatory assets and liabilities – net		(260	)		(720	)
	Other assets		(191	)		(18	)
	Other liabilities		(33	)		75

Net cash provided by operating activities			1,385			1,095

Cash flows from financing activities:
Long-term debt issued			497			638
Long-term debt issuance costs			(5	)		(9	)
Long-term debt repaid			(3	)		(253	)
Bonds purchased			(56	)		—
Preference stock issued – net			123			—
Short-term debt financing – net			200			215
Settlements of stock-based compensation – net			(7	)		(1	)
Dividends paid			(258	)		(125	)

Net cash provided by financing activities			491			465

Cash flows from investing activities:
Capital expenditures			(2,019	)		(1,757	)
Proceeds from sale of nuclear decommissioning trust investments			1,146			600
Purchases of nuclear decommissioning trust investments and other			(1,230	)		(697	)
Customer advances for construction and other investments			12			9
Effect of deconsolidation of variable interest entities			—			(92	)

Net cash used by investing activities			(2,091	)		(1,937	)

Net decrease in cash and cash equivalents			(215	)		(377	)
Cash and cash equivalents, beginning of period			257			462

Cash and cash equivalents, end of period		$	42		$	85

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

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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 ("GAAP") for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and six-month periods ended June 30, 2011 are not necessarily indicative of the operating results for the full year.

The December 31, 2010 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $16 million and $243 million at June 30, 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 $185 million and $196 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at June 30, 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. Inventory consisted of the following:

(in millions)	June 30, 2011		December 31, 2010


Fuel	$	20	$	21
Materials and supplies, spare parts		311		311

Total inventory	$	331	$	332

New Accounting Guidance

Accounting Guidance Adopted in 2011

Fair Value Measurements and Disclosures

The Financial Accounting Standards Board ("FASB") issued an accounting standards update modifying the disclosure requirements related to fair value measurements. Under these requirements, purchases and

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settlements for Level 3 fair value measurements are presented on a gross basis, rather than net. SCE adopted this guidance effective January 1, 2011.

Accounting Guidance Not Yet Adopted

Fair Value Measurement

In May 2011, the FASB issued an accounting standards update modifying the fair value measurement and disclosure guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the value be based on the individual security. This amendment also results in new disclosures primarily related to Level 3 measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. SCE will adopt this guidance effective January 1, 2012 and does not expect the adoption of this standard will have a material impact on SCE's consolidated statements of income, financial position or cash flows.

Presentation of Comprehensive Income

In June 2011, the FASB issued an accounting standards update on the presentation of comprehensive income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. SCE will adopt this guidance effective January 1, 2012. SCE currently presents the statement of comprehensive income immediately following the statement of income and expects to continue to do so. The adoption of this accounting standards update does not change the items that constitute net income and other comprehensive income.

Note 2. Consolidated Statements of Changes in Equity

The following table provides the changes in equity for the six months ended June 30, 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		—		—			—			462			—		462
Other comprehensive income		—		—			2			—			—		2
Dividends declared on common stock		—		—			—			(230	)		—		(230	)
Dividends declared on preferred and preference stock		—		—			—			(29	)		—		(29	)
Stock-based compensation and other		—		3			—			(10	)		—		(7	)
Noncash stock-based compensation and other		—		8			—			—			—		8
Issuance of preference stock		—		(2	)		—			—			125		123

Balance at June 30, 2011	$	2,168	$	581		$	(23	)	$	5,765		$	1,045	$	9,536

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The following table provides the changes in equity for the six months ended June 30, 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		—		—					491			—		—			491
Other comprehensive income		—		—		2			—			—		—			2
Deconsolidation of variable interest entities		—		—		—			—			—		(349	)		(349	)
Dividends declared on preferred and preference stock		—		—		—			(26	)		—		—			(26	)
Stock-based compensation and other		—		2		—			(3	)		—		—			(1	)
Noncash stock-based compensation and other		—		8		—			(4	)		—		—			4

Balance at June 30, 2010	$	2,168	$	561	$	(17	)	$	5,204		$	920	$	—		$	8,836

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.

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

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

As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts. Under these contracts, SCE recovers the costs incurred under its approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 9. As a result, there is no significant potential exposure to loss as a result of SCE's involvement with these VIEs. The aggregate capacity dedicated to SCE for these VIE projects was 3,820 MW at June 30, 2011 and the amounts that SCE paid to these projects were $83 million and $117 million for the three months ended June 30, 2011 and 2010, respectively, and $169 million and $242 million for the six months ended June 30, 2011 and 2010, respectively. These amounts are recovered in customer rates.

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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).

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

		As of June 30, 2011

(in millions)		Level 1		Level 2		Level 3			Collateral			Total

Assets at Fair Value
Money market funds¹		$	16	$	—	$	—		$	—		$	16

Derivative contracts²:
	Electricity		—		—		29			—			29
	Natural gas		—		65		11			—			76
	CRRs		—		—		111			—			111
	Tolling		—		—		41			—			41

Subtotal of derivative contracts			—		65		192			—			257

Long-term disability plan			9		—		—			—			9

Nuclear decommissioning trusts:
	Stocks³		2,062		—		—			—			2,062
	Municipal bonds		—		812		—			—			812
	U.S. government and agency securities		309		118		—			—			427
	Corporate bonds⁴		—		310		—			—			310
	Short-term investments, primarily cash equivalents⁵		4		31		—			—			35

	Sub-total of nuclear decommissioning trusts		2,375		1,271		—			—			3,646

Total assets⁶			2,400		1,336		192			—			3,928

Liabilities at Fair Value
Derivative contracts²:
	Electricity		—		—		64			—			64
	Natural gas		—		239		6			(1	)		244
	Tolling		—		—		481			—			481
Subtotal of derivative contracts			—		239		551			(1	)		789

Total liabilities			—		239		551			(1	)		789

Net assets (liabilities)		$	2,400	$	1,097	$	(359	)	$	1		$	3,139

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		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		$	2,497	$	1,023	$	6	$	4		$	3,530

¹: Money market funds are included in cash and cash equivalents on SCE'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 June 30, 2011 and December 31, 2010, respectively.
⁴: Corporate bonds are diversified, and included $27 million at both June 30, 2011 and December 31, 2010, respectively, for collateralized mortgage obligations and other asset backed securities.
⁵: Excludes net receivables of $11 million and net liabilities of $5 million at June 30, 2011 and December 31, 2010, respectively, of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases.
⁶: Excludes $31 million at both June 30, 2011 and December 31, 2010, respectively, of cash surrender value of life insurance investments for deferred compensation.

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

		Three months ended June 30,						Six months ended June 30,

(in millions)		2011			2010			2011			2010

Fair value of derivative contracts, net assets (liabilities) at beginning of period		$	(127	)	$	(596	)	$	6		$	(111	)
Total realized/unrealized losses, net:
	Included in regulatory assets and liabilities¹		(247	)		(294	)		(382	)		(781	)
Purchases			16			21			17			23
Settlements			(1	)		—			—			—
Transfers into Level 3			—			—			—			—
Transfers out of Level 3			—			—			—			—

Fair value of derivative contracts, net liabilities at end of period		$	(359	)	$	(869	)	$	(359	)	$	(869	)

Change during the period in unrealized losses related to assets and liabilities held at the end of period		$	(240	)	$	(285	)	$	(376	)	$	(749	)

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

Level 2

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

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

Level 3

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

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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 (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 June 30, 2011 and December 31, 2010.

Nuclear Decommissioning Trusts

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

Fair Value of Long-Term Debt Recorded at Carrying Value

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

	June 30, 2011				December 31, 2010

(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Long-term debt, including current portion	$	8,070	$	8,791	$	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

Long-Term Debt

In May 2011, SCE issued $500 million of 3.875% first and refunding mortgage bonds due in 2021. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.

In May 2011, SCE purchased $56 million of its tax-exempt bonds that were subject to remarketing and also converted these bonds to a variable rate structure. These bonds are held by SCE and remain outstanding and have not been retired or cancelled.

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Credit Agreements and Short-Term Debt

At June 30, 2011, SCE's outstanding short-term debt was $200 million at a weighted-average interest rate of 0.33%. 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 June 30, 2011, letters of credit issued under SCE's credit facilities aggregated $71 million and are scheduled to expire in twelve months or less.

Note 6. Derivative Instruments and Hedging Activities

Commodity Price Risk

SCE is exposed to commodity price risk which represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's hedging program reduces ratepayer exposure to variability in market prices related to SCE's power and gas activities. As part of this program, SCE enters into options, swaps, forwards, tolling arrangements and CRRs. These transactions are pre-approved by the California Public Utilities Commission ("CPUC") or executed in compliance with CPUC-approved procurement plans. SCE recovers its related hedging costs through the energy resource recovery account ("ERRA") balancing account, and as a result, exposure to commodity price risk is not expected to impact earnings, but may impact cash flows.

SCE's electricity price exposure arises from electricity purchased from and sold to the California and other wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities, power purchase agreements and California Department of Water Resources ("CDWR") contracts allocated to SCE.

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

Notional Volumes of Derivative Instruments

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

		Economic Hedges

Commodity	Unit of Measure	June 30, 2011		December 31, 2010

Electricity options, swaps and forwards	GWh		34,471		32,138
Natural gas options, swaps and forwards	Bcf		255		250
CRRs	GWh		147,992		181,291
Tolling arrangements	GWh		105,631		114,599

Fair Value of Derivative Instruments

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

	Derivative Assets									Derivative Liabilities

(in millions)	Short- Term			Long- Term			Subtotal			Short- Term			Long- Term			Subtotal			Net Liability

Non-trading activities
Economic hedges	$	89		$	200		$	289		$	243		$	579		$	822		$	533
Netting and collateral		(11	)		(21	)		(32	)		(12	)		(21	)		(33	)		(1	)

Total	$	78		$	179		$	257		$	231		$	558		$	789		$	532

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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 June 30,						Six months ended June 30,

(in millions)	2011			2010			2011			2010

Realized losses	$	(35	)	$	(38	)	$	(74	)	$	(62	)
Unrealized losses		(227	)		(276	)		(323	)		(857	)

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 $164 million and $67 million as of June 30, 2011 and December 31, 2010, respectively, for which SCE has posted no collateral and $4 million of collateral to its counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2011, SCE would be required to post $12 million of collateral.

Counterparty Default Risk Exposure

As part of SCE's procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. If a counterparty were to default on its contractual obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales of excess energy and realized gains on derivative instruments. All of the contracts that SCE has entered into with counterparties are either entered into under SCE's short-term or long-term procurement plan which has been approved by the CPUC, or the contracts are approved by the CPUC before becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance are not expected to affect earnings, but may temporarily affect cash flows.

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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)		June 30, 2011		December 31, 2010


Collateral provided to counterparties:
	Offset against derivative liabilities	$	1	$	4
	Reflected in other current assets		14		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 June 30,						Six months ended June 30,

(in millions)			2011			2010			2011			2010

Income before income taxes			$	354		$	319		$	713		$	625

Provision for income tax at federal statutory rate of 35%				124			112			249			219
Increase (decrease) in income tax from:
	Items presented with related state income tax, net
		Global settlement related¹		—			(53	)		—			(53	)
		Change in tax accounting method for asset removal costs²		—			(40	)		—			(40	)
	State tax – net of federal benefit			18			19			30			21
	Health care legislation³			—			—			—			39
	Property-related and other			(14	)		(33	)		(28	)		(52	)

Total income tax expense			$	128		$	5		$	251		$	134

Effective tax rate				36	%		2	%		35	%		21	%

¹: During the second quarter of 2010, SCE recognized a $53 million earnings benefit resulting from the acceptance by the California Franchise Tax Board of the tax positions finalized with the Internal Revenue Service ("IRS") in 2009 as part of the Global Settlement.
²: During the second quarter of 2010, the IRS approved SCE's request to change its tax accounting method for asset removal costs primarily related to its infrastructure replacement program. As a result, SCE recognized a $40 million earnings benefit (of which $28 million relates to asset removal costs incurred prior to 2010) from deducting asset removal costs earlier in the construction cycle. These deductions were recorded on a flow-through basis.
³: During the first quarter of 2010, SCE recorded a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.

The decreased benefit provided by property-related and other items was primarily due to lower deductions for internally developed software in 2011 compared to the respective periods 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

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these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.

Accounting for Uncertainty in Income Taxes

Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination. The guidance requires the disclosure of all unrecognized tax benefits, which includes both the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims.

Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits:

(in millions)		2011			2010


Balance at January 1,		$	329		$	482
Tax positions taken during the current year
	Increases		29			31
Tax positions taken during a prior year
	Increases		14			133
	Decreases		(11	)		(42	)
	Decreases for settlements during the period		—			(68	)

Balance at June 30,		$	361		$	536

As of June 30, 2011 and December 31, 2010 $240 million and $225 million, respectively, of the unrecognized tax benefits, if recognized, would impact the effective tax rate.

Edison International's federal income tax returns and its California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 are currently under review by the Franchise Tax Board. The IRS examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010. This included a proposed adjustment to disallow a component of SCE's repair allowance deduction, which if sustained, would result in a federal tax payment of approximately $91 million, including interest through June 30, 2011. Edison International disagrees with the proposed adjustment and filed a protest with the IRS in the first quarter of 2011.

Accrued Interest and Penalties

The total amount of accrued interest and penalties related to SCE's income tax liabilities was $65 million and $61 million as of June 30, 2011 and December 31, 2010, respectively.

The net after-tax interest and penalties recognized in income tax expense was $2 million and $3 million for the three- and six-month periods ended June 30, 2011, respectively, compared to a benefit of $24 million and $22 million for the same periods in 2010.

Note 8. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

During the six months ended June 30, 2011, SCE made contributions of $51 million and during the remainder of 2011, expects to make $54 million of additional contributions. 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 June 30,						Six months ended June 30,

(in millions)	2011			2010			2011			2010

Service cost	$	38		$	29		$	76		$	58
Interest cost		47			49			94			98
Expected return on plan assets		(56	)		(49	)		(112	)		(98	)
Amortization of prior service cost		2			2			4			4
Amortization of net loss		4			6			8			12

Expense under accounting standards		35			37			70			74
Regulatory adjustment – deferred		(6	)		(14	)		(12	)		(28	)

Total expense recognized	$	29		$	23		$	58		$	46

Postretirement Benefits Other Than Pensions

During the six months ended June 30, 2011, SCE made contributions of $11 million and during the remainder of 2011, expects to make $43 million of additional contributions. 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 June 30,						Six months ended June 30,

(in millions)	2011			2010			2011			2010

Service cost	$	10		$	7		$	20		$	14
Interest cost		31			30			62			60
Expected return on plan assets		(27	)		(25	)		(54	)		(50	)
Amortization of prior service cost (credit)		(9	)		(9	)		(18	)		(18	)
Amortization of net loss		9			8			18			16

Total expense	$	14		$	11		$	28		$	22

Stock-Based Compensation

During the six months ended June 30, 2011, Edison International granted its 2011 stock-based compensation awards to SCE employees, which included stock options, performance shares and restricted stock units.

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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		1,806,425			37.98
Expired		(25,104	)		47.24
Forfeited		(163,575	)		33.16
Exercised		(571,051	)		24.42
Affiliate transfers – net		106,728			32.61

Outstanding at June 30, 2011		11,218,159			34.07		6.37

Vested and expected to vest at June 30, 2011		10,953,452			34.08		6.32	$	75

Exercisable at June 30, 2011		6,424,920			34.32		4.78		49

At June 30, 2011, there was $15 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 granted to SCE employees:

	Equity Awards

	Equity Awards					Liability Awards
				Weighted-Average Grant Date Fair Value		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		80,828			30.81		80,828
Forfeited		(48,580	)		52.68		(48,580	)
Affiliate transfers – net		3,097			27.15		3,097

Nonvested at June 30, 2011		255,249			28.04		255,249			29.46

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 June 30, 2011, there was $3 million of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately two years.

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Restricted Stock Units

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

			Weighted-Average Grant Date Fair Value


Nonvested at December 31, 2010	385,877		$	32.90
Granted	134,942			37.98
Forfeited	(12,597	)		31.75
Paid Out	(75,161	)		53.01
Affiliate transfers – net	5,657			29.74

Nonvested at June 30, 2011	438,718			31.88

At June 30, 2011, there was $6 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $2 million in 2011, $3 million in 2012 and $1 million in 2013.

Supplemental Data on Stock Based Compensation

		Three months ended June 30,				Six months ended June 30,

in millions)		2011		2010		2011		2010

Stock based compensation expense¹		$	7	$	5	$	9	$	10
Income tax benefits related to stock compensation expense			3		2		4		4
Excess tax benefits²			1		1		3		2
Stock options
	Cash used to purchase shares to settle options		11		4		22		7
	Cash from participants to exercise stock options		7		2		14		5
	Value of options exercised		4		2		8		2
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 for both the six month periods ended June 30, 2011 and 2010.

Note 9. Commitments and Contingencies

Third-Party Power Purchase Agreements

At June 30, 2011, additional renewable energy power purchase contracts became effective and were classified as operating leases. SCE's additional commitments under these contracts are estimated to be: $6 million in 2011, $116 million each year in 2012 – 2015 and $1.9 billion for the period remaining thereafter.

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

Contingencies

In addition to the matters disclosed in these Notes, SCE is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. SCE believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.

Navajo Nation Litigation

On August 1, 2011, SCE and the other defendants entered into a comprehensive settlement with the Navajo Nation of the litigation filed in June 1999 against SCE and others concerning royalty payments to the Navajo for the coal supplied to the Mohave Generating Station. As amended in April 2010, the Navajo Nation's complaint asserted claims for, among other things, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The settlement will result in a payment to the Navajo Nation and other related parties. As a result of the settlement, the Navajo Nation lawsuit will be dismissed. The settlement agreement reached with the Navajo Nation will not impact SCE's results of operations.

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

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and maintenance, monitoring and site closure. Unless there is a single probable amount, SCE records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.

As of June 30, 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 $54 million, of which $18 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 $192 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 $32 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). In addition, SCE expects to recover 100% of environmental remediation costs incurred at the majority of the remaining sites through customer rates, representing $21 million of its recorded liability. SCE has recorded a regulatory asset of $53 million at June 30, 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 $5 million to $17 million. Costs incurred for the six months ended June 30, 2011 and 2010, were $7 million and $3 million, respectively.

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

Nuclear Insurance

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

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

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and 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,

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SCE could be assessed retrospective premium adjustments of up to approximately $48 million per year. Insurance premiums are charged to operating expense.

Spent Nuclear Fuel

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

In June 2010, the United States Court of Federal Claims issued a decision granting SCE and its co-owners damages of approximately $142 million to recover costs incurred through December 31, 2005 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. The decision 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.

Note 10. Regulatory and Environmental Developments

Environmental Developments

Water Quality

Once-Through Cooling Issues

In March 2011, the US EPA issued proposed standards under the federal Clean Water Act which would affect cooling water intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). The regulations are expected to be finalized by July 2012. SCE is evaluating the proposed standards and 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. If other coastal power plants in California that rely on once-through cooling are forced to shut down or limit operations, the California policy may also significantly impact SCE's ability to procure generating capacity from those plants, which could have an adverse effect on system reliability and the cost of electricity.

Greenhouse Gas Regulation

California Air Resources Board's ("CARB") regulations implementing a California cap-and-trade program continue to be the subject of litigation. In June 2011, the CARB announced that initial cap-and-trade program compliance for the electricity sector would be delayed until January 2013.

In April 2011, California enacted a law requiring that California utilities to procure 33% of their electricity requirements from renewable resources, as defined in the statute. The law requires implementation by the CPUC. The impact of the new 33% law will depend on how the CPUC implements the law, which remains uncertain.

Greenhouse Gas Litigation Developments

In June 2011, the U.S. Supreme Court dismissed public nuisance claims against five power companies, ruling that the CAA and the US EPA actions it authorizes displace federal common law nuisance claims that might arise from the emission of greenhouse gases. The court also affirmed the Second Circuit's

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determination that at least some of the plaintiffs had standing to bring the case. The court did not address whether the CAA also preempts state law claims arising from the same circumstances.

Parties to the Kivalina case, the appeal of which was deferred before the Ninth Circuit Court of Appeals pending the Supreme Court's ruling described above, have requested that the appeal recommence and have asked for permission to file additional briefs on the impact of the Supreme Court's ruling. The Kivalina case was brought by the Alaskan Native Village of Kivalina seeking damages of up to $400 million for the cost of relocating the village because the plaintiffs claim that the Arctic ice that has protected the village is melting as a result of climate change. The federal district court dismissed the case against Edison International and the other defendants in October 2009.

On May 27, 2011, private citizens filed a purported class action complaint in the United States District Court for the Southern District of Mississippi, naming among a large number of defendants, Edison International and its subsidiaries, including SCE . Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of greenhouse gases that have contributed to climate change and sea level rise, which in turn are alleged to have increased the destructive force of Hurricane Katrina. The lawsuit alleges causes of action for negligence, public and private nuisance, and trespass, and seeks unspecified compensatory and punitive damages. The claims in this lawsuit are nearly identical to a subset of the claims that were raised against many of the same defendants in a previous lawsuit that was filed in, and dismissed by, the same federal district court where the current case has been filed.

Note 11. Supplemental Cash Flows Information

SCE's supplemental cash flows information is:

			Six months ended June 30,

(in millions)			2011			2010

Cash payments (receipts) for interest and taxes:
	Interest – net of amounts capitalized		$	179		$	162
	Tax refunds – net			(95	)		(12	)

Noncash investing and financing activities:
	Accrued capital expenditures		$	341		$	286
	Details of debt exchange:
		Pollution-control bonds redeemed	$	(56	)	$	(203	)
		Pollution-control bonds issued		56			203
	Deconsolidation of variable interest entities:
		Assets other than cash	$	—		$	306
		Liabilities and noncontrolling interests		—			(398	)
	Dividends declared but not paid:
		Preferred and preference stock	$	15		$	13

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 for a price of $100 per share plus accrued and unpaid dividends, if any. These shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used for general corporate purposes.

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Note 13. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)		June 30, 2011		December 31, 2010


Current:
	Regulatory balancing accounts	$	268	$	213
	Energy derivatives		194		162
	Other		7		3

			469		378

Long-term:
	Deferred income taxes – net		1,912		1,855
	Pensions and other postretirement benefits		1,089		1,097
	Unamortized generation investment – net		328		355
	Unamortized loss on reacquired debt		258		268
	Energy derivatives		465		177
	Nuclear-related ARO investment – net		163		154
	Unamortized distribution investment – net		125		105
	Regulatory balancing accounts		53		56
	Other		297		280

			4,690		4,347

Total Regulatory Assets		$	5,159	$	4,725

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	June 30, 2011		December 31, 2010


Current:
Regulatory balancing accounts	$	818	$	733
Other		2		5

		820		738

Long-term:
Costs of removal		2,663		2,623
ARO		1,250		1,099
Regulatory balancing accounts		846		802

		4,759		4,524

Total Regulatory Liabilities	$	5,579	$	5,262

Note 14. Other Investments

Nuclear Decommissioning Trusts

Future decommissioning costs of removal of nuclear assets are expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately $23 million per year included in SCE customer rates. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through customer rates. Funds collected, together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.

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The following table sets forth amortized cost and fair value of the trust investments:

		Amortized Cost				Fair Value

(in millions)	Longest Maturity Dates	June 30, 2011		December 31, 2010		June 30, 2011		December 31, 2010

Stocks	—	$	862	$	895	$	2,062	$	2,029
Municipal bonds	2050		699		706		812		790
U.S. government and agency securities	2041		396		270		427		288
Corporate bonds	2054		255		288		310		346
Short-term investments and receivables/payables	One-year		44		26		46		27

Total		$	2,256	$	2,185	$	3,657	$	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 $524 million and $315 million for the three months ended June 30, 2011 and 2010, respectively, and $1.1 billion and $600 million for the six months ended June 30, 2011 and 2010, respectively. Unrealized holding gains, net of losses, were $1.4 billion and $1.3 billion at June 30, 2011 and December 31, 2010, respectively.

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

	Three months ended June 30,						Six months ended June 30,

(in millions)	2011			2010			2011			2010

Balance at beginning of period	$	3,619		$	3,248		$	3,480		$	3,140
Realized gains – net		12			13			35			34
Unrealized gains (losses) – net		4			(205	)		106			(143	)
Other-than-temporary impairments		(4	)		(7	)		(13	)		(11	)
Interest, dividends, contributions and other		26			34			49			63

Balance at end of period	$	3,657		$	3,083		$	3,657		$	3,083

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 June 30,				Six months ended June 30,

(in millions)		2011		2010		2011		2010

Other income:
	Equity AFUDC	$	27	$	25	$	56	$	54
	Increase in cash surrender value of life insurance policies		7		6		13		12
	Other		5		4		8		4

Total other income		$	39	$	35	$	77	$	70

Other expenses:
	Civic, political and related activities and donations	$	9	$	9	$	15	$	15
	Other		4		6		10		11

Total other expenses		$	13	$	15	$	25	$	26

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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;
•: possible customer bypass or departure due to technological advancements or cumulative rate impacts that make self-generation or use of alternative energy sources economically viable;
•: risks associated with the operation of transmission and distribution assets and nuclear and other power generating facilities including: nuclear fuel storage issues, public safety issues, failure, availability, efficiency, output, cost of repairs and retrofits of equipment and availability and cost of spare parts;
•: environmental laws and regulations, both at the state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business;
•: cost of capital and the ability to borrow funds and access to capital markets on reasonable terms;
•: the cost and availability of electricity including the ability to procure sufficient resources to meet expected customer needs in the event of 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;

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•: effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
•: potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;
•: cost and availability of natural gas 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 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- and six-month periods ended June 30, 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- and six-month periods ended June 30, 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 June 30,							Six months ended June 30,

(in millions)		2011		2010		Change			2011		2010			Change

Net income available for common stock		$	211	$	301	$	(90	)	$	433	$	465		$	(32	)
Non-Core Earnings (Loss)
	Global settlement		—		53		(53	)		—		53			(53	)
	Tax impact of health care legislation		—		—		—			—		(39	)		39

Core Earnings		$	211	$	248	$	(37	)	$	433	$	451		$	(18	)

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

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representative of ongoing earnings, such as: settlement of certain tax, regulatory or legal matters or proceedings.

SCE's 2011 core earnings decreased $37 million and $18 million for the quarter and year-to-date, respectively. Core earnings decreased as rate base growth was more than offset by higher income tax expense, including a $40 million benefit in the second quarter of 2010 from a change in tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program.

Non-core items included:

•: An earnings benefit of $53 million recorded in the second quarter of 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement.
•: An after-tax earnings charge of $39 million recorded in the first quarter of 2010 to reverse previously recognized federal tax benefits eliminated by federal health care legislation enacted in 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.

Capital Program

During the first six months of 2011, SCE's capital investment program focused on upgrading and expanding SCE's transmission and distribution system; replacing generation asset equipment; and installing smart meters. Total capital expenditures (including accruals) were $1.6 billion during the first six months of 2011 compared to $1.5 billion 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 "Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2010 MD&A.

In July 2011, the FERC adopted new rules that remove incumbent public utility transmission owners' federally-based right of first refusal to construct certain new transmission facilities. The rules direct regional entities, such as ISOs, to create new processes that would allow other providers to develop new transmission projects. The new processes will not become effective until approved by FERC, which is expected in late 2012. The majority of SCE's 2011 – 2014 transmission capital forecast relates to transmission projects that have been approved by the CAISO and barring a re-evaluation under the new rules, will not be subject to the new processes. The impact of the new rules on future transmission projects will depend on the processes ultimately implemented by regional entities.

2012 CPUC General Rate Case

As discussed in the year-ended 2010 MD&A, SCE filed its GRC application in November 2010. In July 2011, SCE submitted rebuttal testimony in response to intervenor recommendations and updated its requested 2012 base rate revenue requirement to $6.2 billion to reflect agreement on certain issues identified in intervenor testimony. SCE's updated request, after considering the effects of sales growth, would result in incremental customer base rate increases of $794 million, $155 million and $515 million in 2012, 2013 and 2014, respectively. The updated request also reflects a previously submitted base revenue requirement reduction of $38 million, $133 million and $145 million in 2012, 2013, and 2014, respectively, primarily due to a reduction in rate base from inclusion of higher deferred income taxes resulting from bonus depreciation deductions under the 2010 Tax Relief Act.

The Division of Ratepayer Advocates ("DRA") recommended that SCE's requested 2012 base rate revenue requirement be decreased by approximately $850 million, comprised of approximately $630 million in operation and maintenance expense reductions and approximately $220 million in capital-related revenue requirement reductions. The Utility Reform Network or TURN and other intervenors recommended an additional $610 million revenue requirement reduction, beyond the DRA adjustments, primarily capital-related in nature, as well as disallowances of recorded capital costs for specific projects. Intervenors have

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also recommended changes to SCE's proposed post test year ratemaking methodology to be used for 2013 and 2014.

The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011. 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. SCE cannot predict the revenue requirement the CPUC will ultimately authorize.

FERC Formula Rates

In August 2011, the FERC accepted SCE's request to implement a formula rate, effective January 1, 2012, to determine SCE's FERC transmission revenue requirement, including its construction work in progress ("CWIP") incentive revenue requirement that was previously recovered through a separate mechanism, subject to refund and settlement procedures. The FERC reduced SCE's proposed base ROE request from 11.5% to 9.93% (before adding the previously authorized 50 basis point incentive for CAISO participation and individual authorized project incentives). SCE's request proposed the adoption of a specific formula to calculate a forecast revenue requirement that is used to establish rates and is trued-up annually to allow SCE to recover its actual revenue requirement, including its actual cost of service, actual rate base (including the impact of bonus depreciation) and the authorized return on investment. SCE's request also allows SCE to make single-issue rate filings requesting changes to certain elements of the formula, including the base ROE, depreciation rates and the retail rate structure. The FERC order directs SCE to modify its 2012 forecast transmission revenue requirement of $771 million for the lower base ROE. SCE expects to file a request for rehearing of the adopted base ROE within 30 days and cannot predict the formula rate structure or the base ROE that the FERC will ultimately authorize.

Nuclear Industry and Regulatory Response to Events in Japan

As discussed in the 2010 Form 10-K under the heading "Nuclear Power Plant Regulation," SCE is subject to the jurisdiction of the NRC with respect to its ownership interest in San Onofre and Palo Verde. In light of the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the March 2011 earthquake and tsunami, the NRC has been performing and plans to continue to perform additional operational and safety reviews of nuclear facilities in the United States. The NRC also created a Task Force to conduct a systematic review of U.S. NRC processes and regulations to determine whether additional improvements to the existing nuclear regulatory system are warranted in light of the events in Japan. The Task Force issued its initial report in July 2011, which concluded that a sequence of events like the Fukushima accident is unlikely to occur in the U.S., and that continued operation of U.S. reactors does not pose an imminent risk to public health and safety. The Task Force Report also included several proposed changes to regulations applicable to protection against natural phenomena, including earthquakes and flooding, and emergency preparedness. These recommendations must undergo additional review by NRC management and the nuclear industry before any changes are implemented; if implemented, they 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, Greenhouse Gas Litigation Developments 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.

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

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

The following tables summarize SCE's results of operations for the periods indicated. The presentation separately identifies utility earning activities and utility cost-recovery activities.

Three Months Ended June 30, 2011 versus June 30, 2010

		Three months ended June 30, 2011								Three months ended June 30, 2010


(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated

Operating revenue		$	1,383		$	1,063	$	2,446		$	1,308		$	939	$	2,247

Fuel and purchased power			—			732		732			—			706		706
Operations and maintenance			549			297		846			537			218		755
Depreciation, decommissioning and amortization			323			33		356			306			14		320
Property taxes and other			68			1		69			61			1		62

Total operating expenses			940			1,063		2,003			904			939		1,843

Operating income			443			—		443			404			—		404
Net interest expense and other			(89	)		—		(89	)		(85	)		—		(85	)

Income before income taxes			354			—		354			319			—		319
Income tax expense			128			—		128			5			—		5

Net income			226			—		226			314			—		314
Dividends on preferred and preference stock			15			—		15			13			—		13

Net income available for common stock		$	211		$	—	$	211		$	301		$	—	$	301

Core Earnings¹							$	211							$	248
Non-Core Earnings:
	Global Settlement							—								53
	Tax impact of health care legislation							—								—

Total SCE GAAP Earnings							$	211							$	301

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

Utility Earning Activities

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $75 million primarily due to the following:

•: $40 million increase primarily due to a 4.35% increase in 2011 authorized revenue approved in the CPUC 2009 GRC decision.
•: $25 million increase in FERC-related revenue primarily due to CWIP incentive revenue for the Tehachapi transmission project.

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•: $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 transmission and distribution expenditures.
•: Higher income taxes primarily due to a change in tax method of accounting for asset removal costs. See "—Income Taxes" below for further information.

Utility Cost-Recovery Activities

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

•: Higher purchased power expense of $37 million driven by higher average renewable energy contract prices resulting from new contracts entered into to meet the renewable procurement standard requirements, and by increased purchases in 2011 to replace power previously delivered under CDWR contracts which have since expired.
•: Higher operation and maintenance expense of $79 million resulting primarily from increased energy efficiency program costs.
•: Higher depreciation, decommissioning and amortization expense of $19 million primarily related to the steam generator replacement project and the EdisonSmartConnect™ project.

Six Months Ended June 30, 2011 versus June 30, 2010

		Six months ended June 30, 2011								Six months ended June 30, 2010


(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated

Operating revenue		$	2,746		$	1,932	$	4,678		$	2,573		$	1,833		$	4,406

Fuel and purchased power			—			1,317		1,317			—			1,395			1,395
Operations and maintenance			1,078			553		1,631			1,057			411			1,468
Depreciation, decommissioning and amortization			641			59		700			605			24			629
Property taxes and other			143			3		146			129			1			130

Total operating expenses			1,862			1,932		3,794			1,791			1,831			3,622

Operating income			884			—		884			782			2			784
Net interest expense and other			(171	)		—		(171	)		(157	)		(2	)		(159	)

Income before income taxes			713			—		713			625			—			625
Income tax expense			251			—		251			134			—			134

Net income			462			—		462			491			—			491
Dividends on preferred and preference stock			29			—		29			26			—			26

Net income available for common stock		$	433		$	—	$	433		$	465		$	—		$	465

Core Earnings¹							$	433								$	451
Non-Core Earnings:
	Global Settlement							—									53
	Tax impact of health care legislation							—									(39	)

Total SCE GAAP Earnings							$	433								$	465

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

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Utility Earning Activities

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $173 million primarily due to the following:

•: $80 million increase primarily due to a 4.35% increase in 2011 authorized revenue approved in the CPUC 2009 GRC decision.
•: $60 million increase in FERC-related revenue primarily due to CWIP incentive revenue for the Tehachapi transmission project and the implementation of the 2010 FERC rate case effective March 1, 2010.
•: $30 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 $36 million primarily related to increased transmission and distribution expenditures.

•

Higher net interest expense and other of $14 million primarily due to higher outstanding balances on long-term debt.

•

Higher income taxes primarily due to a change in tax method of accounting for asset removal costs. See "—Income Taxes" below for more information.

Utility Cost-Recovery Activities

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

•: Lower purchased power expense of $62 million driven by reduced purchases resulting from increased utility owned generation production in 2011, as compared to 2010, primarily due to 2010 outages at San Onofre and Four Corners. The decrease was partially offset by higher average renewable energy contract prices resulting from new contracts entered into to meet the renewable procurement standard requirements, and by increased purchases in 2011 to replace power previously delivered under CDWR contracts which have since expired.
•: $16 million decrease in fuel expense primarily due to lower production at Mountainview in 2011, partially offset by lower nuclear fuel expense in 2010 resulting from the San Onofre Unit 2 extended outage.
•: Higher operation and maintenance expense of $142 million resulting primarily from increased energy efficiency program costs.
•: Higher depreciation, decommissioning and amortization expense of $35 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 $2.4 billion and $4.5 billion for the three- and six-month periods ended June 30, 2011, respectively, compared to $2.4 billion and $4.4 billion for the respective periods in 2010. The year-to-date increase reflects a rate increase of $40 million and a sales volume increase of $60 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 a CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk or benefit related to retail electricity sales (see "Item 1. Business—Overview of Ratemaking Mechanisms" in the 2010 Form 10-K).

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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 $280 million and $555 million for the three- and six-month periods ended June 30, 2011, respectively, and $286 million and $582 million for the respective periods in 2010. The CDWR-related rates in 2011 continue to reflect an approximately $585 million refund of operating reserves that CDWR can release as their contracts terminate. Total customer rates are expected to increase as CDWR operating reserves are fully refunded. The power contracts that CDWR allocated to SCE will terminate by the end of 2011; however, the refund of operating reserves is expected to continue through 2012. SCE's revenue and related purchased power expense is expected to increase as these CDWR contracts are replaced by power purchase agreements entered into by SCE.

Income Taxes

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

			Three months ended June 30,						Six months ended June 30,

(in millions)			2011			2010			2011			2010

Income before income taxes			$	354		$	319		$	713		$	625

Provision for income tax at federal statutory rate of 35%			$	124		$	112		$	249		$	219
Increase (decrease) in income tax from:
	Items presented with related state income tax, net
		Global settlement related¹		—			(53	)		—			(53	)
		Change in tax accounting method for asset removal costs²		—			(40	)		—			(40	)
	State tax – net of federal benefit			18			19			30			21
	Health care legislation³			—			—			—			39
	Property-related and other			(14	)		(33	)		(28	)		(52	)

Total income tax expense			$	128		$	5		$	251		$	134

Effective tax rate				36	%		2	%		35	%		21	%

¹: During the second quarter of 2010, SCE recognized a $53 million earnings benefit resulting from the acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement.
²: During the second quarter of 2010, the IRS approved SCE's request to change its tax accounting method for asset removal costs primarily related to its infrastructure replacement program. As a result, SCE recognized a $40 million earnings benefit (of which $28 million relates to asset removal costs incurred prior to 2010) from deducting asset removal costs earlier in the construction cycle. These deductions are recorded on a flow-through basis.
³: During the first quarter of 2010, SCE recorded a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.

The decreased benefit provided by property-related and other items was primarily due to lower deductions for internally developed software in 2011 compared to the respective periods in 2010.

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

LIQUIDITY AND CAPITAL RESOURCES

SCE's ability to operate its business, 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

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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 June 30, 2011, SCE had approximately $46 million of cash and equivalents and short-term investments. 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		(71	)

Amount available	$	2,623

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 June 30, 2011, SCE's debt to total capitalization ratio was 0.47 to 1.

Dividend Restrictions

The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 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 June 30, 2011, SCE's 13-month weighted-average common equity component of total capitalization was 50.7% resulting in the capacity to pay $460 million in additional dividends.

During the first six months of 2011, SCE made $230 million in dividend payments to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the actual level of capital expenditures, operating cash flows and earnings.

Margin and Collateral Deposits

Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of June 30, 2011.

(in millions)


Collateral posted as of June 30, 2011¹	$	86
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade		71

Posted and potential collateral requirements²	$	157

¹: Collateral provided to counterparties and other brokers consisted of $1 million which was offset against net derivative liabilities and $85 million, which consisted of $14 million in cash reflected in "Other current assets" on the consolidated balance sheets and $71 million in letters of credit.
²: Total posted and potential collateral requirements may increase by an additional $20 million, based on SCE's forward positions as of June 30, 2011, due to adverse market price movements over the remaining life of the existing power procurement contracts using a 95% confidence level.

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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 June 30, 2011, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $201 million for its workers compensation self-insurance plan.

Historical Consolidated Cash Flows

Condensed Consolidated Statement of Cash Flows

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

	Six months ended June 30,

(in millions)	2011			2010

Net cash provided by operating activities	$	1,385		$	1,095
Net cash provided by financing activities		491			465
Net cash used by investing activities		(2,091	)		(1,937	)

Net decrease in cash and cash equivalents	$	(215	)	$	(377	)

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased $290 million in the first six months of 2011 compared to the first six months of 2010. The increase reflects higher receipts from customers due to increases in authorized revenue and lower tax payments resulting from bonus depreciation. These increases were partially offset by net cash outflows related to regulatory balancing account activities. The operating cash flows were also impacted by the timing of cash receipts and disbursements related to working capital.

Net Cash Provided by Financing Activities

Net cash provided by financing activities for the first six months of 2011 was $491 million consisting of the following significant events:

•: Issued $500 million of 3.875% first and refunding mortgage bonds due in 2021. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.
•: Issued $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. The proceeds from the issuance were used for general corporate purposes.
•: Paid $230 million of dividends to Edison International.
•: Purchased $56 million of its tax-exempt bonds that were subject to remarketing.

Net cash provided by financing activities for the first six months of 2010 was $465 million consisting of the following significant events:

•: Reissued $144 million of tax-exempt pollution control bonds due in 2035. The proceeds from these bonds were used to repay commercial paper borrowings and for general corporate purposes.
•: 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.

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•: Issued $215 million of short-term debt 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 $2.0 billion and $1.8 billion for the six months ended June 30, 2011 and 2010, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $84 million and $97 million for the six months ended June 30, 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."

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 June 30, 2011, SCE had 24 identified material sites for remediation and recorded an estimated minimum liability of $54 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 to mitigate SCE's exposure to commodity price risk was a net liability of $532 million and $207 million at June 30, 2011 and December 31, 2010, respectively. For further discussion of fair value measurements and the fair value hierarchy, see "Edison International Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."

Credit Risk

Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these agreements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of

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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 June 30, 2011, the amount of balance sheet exposure as described above, by the credit ratings of SCE's counterparties, was as follows:

		June 30, 2011

(in millions)		Exposure²		Collateral			Net Exposure

S&P Credit Rating¹
	A or higher	$	130	$	—		$	130
	A-		9		—			9
	Not rated³		41		(31	)		10

Total		$	180	$	(31	)	$	149

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.

The credit risk exposure set forth in the table above is composed of $4 million of net accounts receivable and $176 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 reference.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SCE's management, under the supervision and with the participation of the company's President and Chief Financial Officer, has evaluated the effectiveness of SCE's disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based on that evaluation, the President and Chief Financial Officer have concluded that, as of the end of the period, SCE's disclosure controls and procedures are effective.

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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 ("NOV Recipients") related to activity on a property that was used for equipment storage related to a nearby SCE electricity line undergrounding construction project. The NOV alleged that SCE, through its contractor, violated the California Coastal Act by removing without the appropriate permits approximately one acre of vegetation from the property, which was located in a protected coastal zone within and adjacent to the City of Newport Beach, California. In late 2010, SCE tendered an indemnification claim to its contractor for liability associated with the NOV, which the contractor accepted. In April 2011, the NOV Recipients entered into a Consent Order with the Coastal Commission to resolve the NOV Recipients' liability to the Coastal Commission under the Coastal Act. On June 10, 2011, the NOV Recipients entered into a Settlement Agreement to resolve any remaining claims among themselves pertaining to the NOV.

Navajo Nation Litigation

Developments related to the Navajo Nation litigation are discussed in "SCE Notes to Consolidated Financial Statements Note 9. Commitments and Contingencies—Contingencies—Navajo Nation Litigation."

ITEM 6. EXHIBITS


	10.1		Edison International and Southern California Edison Company Director Compensation Schedule, as adopted June 23, 2011 (File 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2011)*
	10.2		Edison International 2007 Performance Incentive Plan, Amended and Restated as of February 24, 2011 (File 1-9936, filed as Exhibit 10.1 to Edison International's Form 8-K dated April 28, 2011 and filed on April 29, 2011)*
	31.1		Certification of the President 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 June 30, 2011, filed on August 4, 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: August 4, 2011

SOUTHERN CALIFORNIA EDISON Co - FORM 10-Q - August 4, 2011

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SOUTHERN CALIFORNIA EDISON Co Reports