SOUTHERN CALIFORNIA EDISON (SCE-PN) 10-Q 2010 Q3 Quarterly report

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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 September 30, 2010
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from                        to
Commission File Number 1-2313

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.

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 October 26, 2010
Common Stock, no par value	434,888,104

TABLE OF CONTENTS

GLOSSARY				i
PART I. FINANCIAL INFORMATION				1
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. Derivative Instruments and Hedging Activities			7
	Note 3. Liabilities and Lines of Credit			9
	Note 4. Income Taxes			10
	Note 5. Compensation and Benefit Plans			12
	Note 6. Commitments and Contingencies			14
	Note 7. Consolidated Statements of Changes in Equity			20
	Note 8. Supplemental Cash Flows Information			21
	Note 9. Fair Value Measurements			21
	Note 10. Regulatory Assets and Liabilities			27
	Note 11. Other Income and Expenses			28
	Note 12. Variable Interest Entities			28
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				32
	FORWARD-LOOKING STATEMENTS			32
	MANAGEMENT OVERVIEW			34
	Introduction			34
	Highlights of Operating Results			34
	SCE Capital Program			35
	2012 General Rate Case			36
	Environmental Developments			36
	RESULTS OF OPERATIONS			36
	Electric Utility Results of Operations			37
		Three Months Ended September 30, 2010 versus September 30, 2009		37
			Utility Earning Activities	38
			Utility Cost-Recovery Activities	38
		Nine Months Ended September 30, 2010 versus September 30, 2009		39
			Utility Earning Activities	39
			Utility Cost-Recovery Activities	41
		Supplemental Operating Revenue Information		41
		Income Taxes		42

	LIQUIDITY AND CAPITAL RESOURCES			42
	Available Liquidity			42
		Debt Covenant		43
	Regulatory Proceedings			43
		Energy Efficiency Risk/Reward Incentive Mechanism		43
		2010 FERC Rate Case		43
	Dividend Restrictions			43
	Income Tax Matters			44
	Margin and Collateral Deposits			44
	Historical Consolidated Cash Flows			44
		Condensed Consolidated Statement of Cash Flows		44
			Cash Flows Provided by Operating Activities	45
			Cash Flows Provided (Used) by Financing Activities	45
			Cash Flows Used by Investing Activities	45
	Contractual Obligations and Contingencies			46
		Contractual Obligations		46
		Contingencies		46
			Environmental Remediation	46
	MARKET RISK EXPOSURES			46
	Interest Rate Risk			46
	Commodity Price Risk			47
		Natural Gas and Electricity Price Risk		47
	Credit Risk			48
	NEW ACCOUNTING GUIDANCE			48
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				48
ITEM 4T. CONTROLS AND PROCEDURES				48
	Disclosure Controls and Procedures			48
	Internal Control Over Financial Reporting			49
PART II. OTHER INFORMATION				49
ITEM 1. LEGAL PROCEEDINGS				49
	Navajo Nation Litigation			49
	California Coastal Commission Potential Environmental Proceeding			49
ITEM 6. EXHIBITS				49
SIGNATURE				50

GLOSSARY

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

2009 Form 10-K	SCE's Annual Report on Form 10-K for the year ended December 31, 2009
AB	Assembly Bill
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
DCR	Devers-Colorado River
DOE	U. S. Department of Energy
DRA	Division of Ratepayer Advocates
DWP	Los Angeles Department of Water & Power
ERRA	energy resource recovery account
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FGIC	Financial Guarantee Insurance Company
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
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
Investor-Owned Utilities	SCE, SDG&E and PG&E
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
Moody's	Moody's Investors Service
Mohave	two coal fueled electric generating facilities that no longer operate located in Clark County, Nevada in which SCE holds a 56% ownership interest
MRTU	Market Redesign Technical Upgrade
MW	megawatts
MWh	megawatt-hours
NAAQS	national ambient air quality standards
NERC	North American Electric Reliability Corporation
Ninth Circuit	U.S. Court of Appeals for the Ninth Circuit
NOx	nitrogen oxide

i

NRC	Nuclear Regulatory Commission
NSR	New Source Review
Palo Verde	large pressurized water nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest
PBOP(s)	postretirement benefits other than pension(s)
PBR	Performance-based ratemaking
PG&E	Pacific Gas & Electric Company
PSD	Prevention of Significant Deterioration
QF(s)	qualifying facility(ies)
RICO	Racketeer Influenced and Corrupt Organization
ROE	return on equity
S&P	Standard & Poor's Ratings Services
San Onofre	large pressurized water nuclear electric generating facility located in south San Clemente, California in which SCE holds a 78.21% ownership interest
SCAQMD	South Coast Air Quality Management District
SCE	Southern California Edison Company
SDG&E	San Diego Gas & Electric
SEC	U.S. Securities and Exchange Commission
SIP(s)	State Implementation Plan(s)
SO2	sulfur dioxide
SRP	Salt River Project Agricultural Improvement and Power District
The Tribes	Navajo Nation and Hopi Tribe
TURN	The Utility Reform Network
US EPA	U.S. Environmental Protection Agency
VIE(s)	variable interest entity(ies)

ii

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Statements of Income	Southern California Edison Company
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2010			2009			2010			2009
	(Unaudited)
Operating revenue	$	3,098		$	3,069		$	7,504		$	7,531
Fuel		100			177			275			533
Purchased power		1,118			1,032			2,337			2,155
Operation and maintenance		803			802			2,272			2,222
Depreciation, decommissioning and amortization		316			302			945			877
Property and other taxes		65			60			195			187
Gain on sale of assets		—			—			(1	)		(1	)
Total operating expenses		2,402			2,373			6,023			5,973
Operating income		696			696			1,481			1,558
Interest income		2			4			5			9
Other income		33			69			103			126
Interest expense – net of amounts capitalized		(109	)		(105	)		(315	)		(320	)
Other expenses		(10	)		(13	)		(39	)		(33	)
Income before income taxes		612			651			1,235			1,340
Income tax expense		205			236			338			159
Net income		407			415			897			1,181
Less: Net income attributable to noncontrolling interests		—			56			—			90
Dividends on preferred and preference stock not     subject to mandatory redemption		13			13			39			38
Net income available for common stock	$	394		$	346		$	858		$	1,053

Consolidated Statements of Comprehensive Income
			Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)			2010		2009		2010		2009
			(Unaudited)
Net income			$	407	$	415	$	897	$	1,181
Other comprehensive income, net of tax:
	Pension and postretirement benefits other than pensions:
		Amortization of net loss included in net income		—		—		2		1
Comprehensive income				407		415		899		1,182
Less: Comprehensive income attributable to noncontrolling interests				—		56		—		90
Comprehensive income attributable to SCE			$	407	$	359	$	899	$	1,092

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)		September 30, 2010			December 31, 2009
		(Unaudited)
ASSETS
Cash and equivalents		$	857		$	462
Short-term investments			4			9
Receivables, less allowances of $59 and $53 for uncollectible accounts at respective dates			887			719
Accrued unbilled revenue			612			347
Inventory			326			337
Derivative assets			69			160
Regulatory assets			404			120
Other current assets			69			175
Total current assets			3,228			2,329
Nonutility property – less accumulated depreciation of $98 and $744 at respective dates			69			324
Nuclear decommissioning trusts			3,347			3,140
Other investments			84			67
Total investments and other assets			3,500			3,531
Utility plant, at original cost:
Transmission and distribution			23,747			22,214
Generation			2,731			2,667
Accumulated depreciation			(6,097	)		(5,921	)
Construction work in progress			3,020			2,701
Nuclear fuel, at amortized cost			340			305
Total utility plant			23,741			21,966
Derivative assets			192			187
Regulatory assets			5,227			4,139
Other long-term assets			339			322
Total long-term assets			5,758			4,648
Total assets		$	36,227		$	32,474

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, except share amounts)		September 30, 2010			December 31, 2009
		(Unaudited)
LIABILITIES AND EQUITY
Current portion of long-term debt		$	—		$	250
Accounts payable			1,146			1,282
Accrued taxes			150			9
Accrued interest			98			162
Customer deposits			224			238
Derivative liabilities			225			102
Regulatory liabilities			804			367
Other current liabilities			513			637
Total current liabilities			3,160			3,047
Long-term debt			7,626			6,490
Deferred income taxes			4,173			3,651
Deferred investment tax credits			98			97
Customer advances			114			119
Derivative liabilities			1,298			496
Pensions and benefits			1,757			1,681
Asset retirement obligations			3,326			3,198
Regulatory liabilities			3,663			3,328
Other deferred credits and other long-term liabilities			1,879			1,652
Total deferred credits and other liabilities			16,308			14,222
Total liabilities			27,094			23,759
Commitments and contingencies (Note 6)
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			566			551
Accumulated other comprehensive loss			(17	)		(19	)
Retained earnings			5,496			4,746
Total common shareholder's equity			8,213			7,446
Preferred and preference stock not subject to mandatory redemption			920			920
Noncontrolling interests			—			349
Total equity			9,133			8,715
Total liabilities and equity		$	36,227		$	32,474

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

3

Consolidated Statements of Cash Flows	Southern California Edison Company
		Nine Months Ended September 30,
(in millions)		2010			2009
		(Unaudited)
Cash flows from operating activities:
Net income		$	897		$	1,181
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization			945			877
Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)			106			133
Other amortization			82			88
Stock-based compensation			12			10
Deferred income taxes and investment tax credits			336			353
Changes in operating assets and liabilities:
Receivables			(197	)		(243	)
Inventory			(5	)		33
Margin and collateral deposits – net of collateral received			1			20
Prepaid taxes			33			178
Other current assets			(279	)		(283	)
Accounts payable			(3	)		146
Accrued taxes			140			(101	)
Other current liabilities			(103	)		(25	)
Derivative assets and liabilities – net			1,012			(359	)
Regulatory assets and liabilities – net			(530	)		951
Other assets			(26	)		(147	)
Other liabilities			235			469
Net cash provided by operating activities			2,656			3,281
Cash flows from financing activities:
Long-term debt issued			1,135			750
Long-term debt issuance costs			(16	)		(11	)
Long-term debt repaid			(256	)		(153	)
Bonds repurchased			—			(219	)
Short-term debt financing – net			—			(1,893	)
Settlements of stock-based compensation – net			(2	)		4
Distributions to noncontrolling interest			—			(94	)
Dividends paid			(239	)		(238	)
Net cash provided (used) by financing activities			622			(1,854	)
Cash flows from investing activities:
Capital expenditures			(2,659	)		(2,109	)
Proceeds from sale of nuclear decommissioning trust investments			903			1,814
Purchases of nuclear decommissioning trust investments and other			(1,036	)		(1,977	)
Sales of short-term investments			6			1
Purchases of short-term investments			(1	)		(1	)
Customer advances for construction and other investments			(4	)		(12	)
Effect of deconsolidation of variable interest entities			(92	)		—
Net cash used by investing activities			(2,883	)		(2,284	)
Net increase (decrease) in cash and equivalents			395			(857	)
Cash and equivalents, beginning of period			462			1,611
Cash and equivalents, end of period		$	857		$	754

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

SCE is a rate-regulated electric utility that supplies electric energy to a 50,000 square-mile area of central, coastal and 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 2009 Form 10-K. SCE follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2010, as discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with such financial statements.

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and nine-month periods ended September 30, 2010 are not necessarily indicative of the operating results for the full year.

The December 31, 2009 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Cash and Equivalents

Cash equivalents included money market funds totaling $825 million and $360 million at September 30, 2010 and December 31, 2009, respectively. The carrying value of cash equivalents approximates the fair value, as all investments have maturities of three months or less. For further discussion of money market funds, see Note 9.

SCE temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. SCE reclassified $320 million and $224 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at September 30, 2010 and December 31, 2009, respectively.

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers, and cash received from counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the positions. SCE nets margin and cash collateral deposits subject to a master netting arrangement with its derivative

5

positions on its consolidated balance sheets. The following table summarizes margin and collateral deposits provided to and received from counterparties:

(in millions)		September 30, 2010		December 31, 2009
		(Unaudited)
Collateral provided to counterparties:
	Offset against derivative liabilities	$	5	$	—
	Reflected in other current assets		2		6
Collateral received from counterparties:
	Reflected in other current liabilities		56		59

New Accounting Guidance

Accounting Guidance Adopted in 2010

Consolidation—Improvements to Financial Reporting by Enterprises Involved with Variable
Interest Entities

The FASB issued an accounting standards update that changes how a company determines when an entity, that is insufficiently capitalized or is not controlled through voting (or similar rights), should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an ability to direct the activities of the entity that most significantly impact the entity's economic performance and whether the entity has an obligation to absorb losses or the right to receive expected returns of the entity. This guidance requires a company to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. SCE adopted this guidance prospectively effective January 1, 2010. The impact of adopting this guidance resulted in the deconsolidation of projects related to four QF contracts. For further discussion, see Note 12.

Fair Value Measurements and Disclosures

The FASB issued an accounting standards update that provides for new disclosure requirements related to fair value measurements. The requirements, which SCE adopted effective January 1, 2010, include separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. The update also clarified existing disclosure requirements for the level of disaggregation, inputs and valuation techniques. In addition, effective January 1, 2011, the Level 3 reconciliation of fair value measurements using significant unobservable inputs should include gross rather than net information about purchases, sales, issuances and settlements. The guidance impacts disclosures only. For further discussion, see Note 9.

Accounting Guidance Not Yet Adopted

Final accounting pronouncements issued by the FASB effective after September 30, 2010 are not expected to have a material effect on SCE's consolidated results of operations, financial position or cash flows.

6

Note 2. Derivative Instruments and Hedging Activities

Commodity Price Risk

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

SCE's electricity price exposure arises from energy purchased and sold in the MRTU market as a result of differences between SCE's load requirements versus the amount of energy delivered from its generating facilities, existing bilateral contracts and CDWR contracts allocated to SCE.

A portion of SCE's purchased power supply is subject to natural gas price volatility. SCE's natural gas price exposure arises from purchasing natural gas for generation at the Mountainview power plant and peaker plants, bilateral contracts where pricing is based on natural gas prices (this includes contract energy prices for some renewable QFs which are based on the monthly index price of natural gas delivered at the southern California border), and power contracts in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.

Notional Volumes of Derivative Instruments

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

		Economic Hedges
Commodity	Unit of Measure	September 30, 2010		December 31, 2009
		(Unaudited)
Electricity options, swaps and forward arrangements	GWh		12,721		14,868
Natural gas options, swaps and forward arrangements	Bcf		272		266
Congestion revenue rights	GWh		146,538		195,367
Tolling arrangements1	GWh		115,681		116,398

¹

In compliance with a CPUC mandate, SCE held an open, competitive solicitation that produced agreements with different project developers who have agreed to construct new southern California generating resources. SCE has entered into a number of contracts which are recorded as derivative instruments. The contracts provide for fixed capacity payments as well as pricing for energy delivered based on a heat rate and contractual operation and maintenance prices. However, due to uncertainty regarding the availability of required emission credits, some of the new generating resources may not be constructed and the contracts associated with these resources could therefore terminate, at which time SCE would no longer account for these contracts as derivatives.

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Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at September 30, 2010:

		Derivative Assets						Derivative Liabilities
(in millions)		Short- Term		Long- Term		Subtotal		Short- Term			Long- Term		Subtotal			Net Liability
		(Unaudited)
Non-trading activities:
	Economic hedges	$	69	$	192	$	261	$	230		$	1,298	$	1,528		$	1,267
	Netting and collateral		—		—		—		(5	)		—		(5	)		(5	)
Total		$	69	$	192	$	261	$	225		$	1,298	$	1,523		$	1,262

The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2009:

		Derivative Assets						Derivative Liabilities
(in millions)		Short- Term		Long- Term		Subtotal		Short- Term		Long- Term		Subtotal		Net Liability
		(Unaudited)
Non-trading activities:
	Economic hedges	$	160	$	187	$	347	$	102	$	496	$	598	$	251

Income Statement Impact of Derivative Instruments

SCE recognizes realized gains and losses on derivative instruments as purchased-power expense and recovers these costs, subject to reasonableness review, 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 or 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 September 30,						Nine Months Ended September 30,
(in millions)	2010			2009			2010			2009
	(Unaudited)
Realized loss	$	(53	)	$	(113	)	$	(116	)	$	(307	)
Unrealized gain (loss)		(165	)		(198	)		(1,022	)		428

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

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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 $240 million and $91 million, as of September 30, 2010 and December 31, 2009, respectively, for which SCE has posted no collateral to its counterparties. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2010, SCE would be required to post $16 million of additional collateral based on the contractual terms.

Note 3. Liabilities and Lines of Credit

Long-Term Debt

In March 2010, SCE issued $500 million of 5.5% first and refunding mortgage bonds due in 2040. In May 2010, SCE reissued $144 million of 5.0% tax-exempt pollution control bonds due in 2035. In August 2010, SCE issued $500 million of 4.5% first and refunding mortgage bonds due in 2040. These issuances are part of long-term financing plans to fund SCE's capital program.

Credit Agreements and Short-Term Debt

In March 2010, SCE replaced its $500 million 364-day revolving credit facility with a new $500 million three-year credit facility that terminates in March 2013.

At September 30, 2010, letters of credit issued under SCE's credit facilities aggregated $11 million and are scheduled to expire in twelve months or less.

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Note 4. Income Taxes

Effective Tax Rate

The table below contains a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations attributable to common shareholders:

			Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)			2010			2009		2010			2009
			(Unaudited)
Provision for income tax at federal statutory rate of 35%			$	214		$	208	$	433		$	438
Increase (decrease) in income tax from:
	Items presented with related state income tax, net
		Global settlement related		(42	)		—		(95	)		(300	)
		Change in tax accounting method for asset removal costs		—			—		(40	)		—
	State tax – net of federal benefit			26			28		47			55
	Health care legislation			—			—		39			—
	Property-related and other			7			—		(46	)		(34	)
Total income tax expense from continuing operations			$	205		$	236	$	338		$	159
Pre-tax income from continuing operations			$	612		$	595	$	1,235		$	1,250
Effective tax rate				33%			40%		27%			13%

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

Global Settlement

During 2010, SCE recognized a $95 million earnings benefit relating to the California impact of the federal Global Settlement, including $53 million in the second quarter resulting from acceptance by the Franchise Tax Board of the tax positions finalized with the IRS in 2009 and $42 million in the third quarter resulting from receipt of the final interest determination from the Franchise Tax Board. During the nine months ended September 30, 2009 SCE recognized a $300 million earnings benefit related to the Global Settlement finalized with the IRS (described in "Item 8. SCE Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K).

Change in Tax Accounting Method for Asset Removal Costs

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 ($28 million of which 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.

Health Care Legislation

During the first quarter of 2010, SCE recognized a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010.

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The Patient Protection and Affordable Care Act, as modified by the Health Care and Education Reconciliation Act, includes a provision that eliminates the federal tax deduction of retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies. Although this change does not take effect until January 1, 2013, SCE is required to recognize the full accounting impact of the legislation in its financial statements in the period of enactment.

Accounting for Uncertainty in Income Taxes

Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits from January 1 to September 30 for 2010 and 2009:

(in millions)		2010			2009
		(Unaudited)
Balance at January 1		$	482		$	2,066
Tax positions taken during the current year:
	Increases		65			48
Tax positions taken during a prior year:
	Increases		185			155
	Decreases		(14	)		(30	)
Decreases for settlements during the period			(68	)		(1,741	)
Balance at September 30		$	650		$	498

As of September 30, 2010 and December 31, 2009, respectively, if recognized, $191 million and $179 million of unrecognized tax benefits would impact the effective tax rate.

Accrued Interest and Penalties

The total amount of accrued interest and penalties related to SCE's income tax liabilities was $105 million and $79 million as of September 30, 2010 and December 31, 2009, respectively.

The net after-tax interest and penalties recognized in income tax expense was a benefit of $27 million for the three months ended September 30, 2010, compared to an expense of $5 million for the same period in 2009. Net after-tax interest and penalties recognized in income tax expense was a benefit of $48 million and $284 million for the nine months ended September 30, 2010 and 2009, respectively.

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Note 5. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

During the nine months ended September 30, 2010, SCE made 2010 plan year contributions of $72 million and expects to make $25 million of additional contributions during the remainder of 2010. SCE recovers contributions made to most of its pension plans through CPUC-approved regulatory mechanisms. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.

Expense components are:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2010			2009			2010			2009
	(Unaudited)
Service cost	$	29		$	27		$	87		$	81
Interest cost		49			48			147			144
Expected return on plan assets		(49	)		(40	)		(147	)		(120	)
Amortization of prior service cost		2			4			6			12
Amortization of net loss		6			13			18			39
Expense under accounting standards	$	37		$	52		$	111		$	156
Regulatory adjustment – deferred		(14	)		(24	)		(42	)		(72	)
Total expense recognized	$	23		$	28		$	69		$	84

Postretirement Benefits Other Than Pensions

During the nine months ended September 30, 2010, SCE made 2010 plan year contributions of $18 million and expects to make $29 million of additional contributions during the remainder of 2010. SCE's annual contributions are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to its total annual expense.

Expense components are:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2010			2009			2010			2009
	(Unaudited)
Service cost	$	7		$	7		$	21		$	21
Interest cost		30			29			90			88
Expected return on plan assets		(25	)		(20	)		(75	)		(60	)
Amortization of prior service cost (credit)		(9	)		(7	)		(27	)		(21	)
Amortization of net loss		8			11			24			32
Total expense	$	11		$	20		$	33		$	60

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Stock-Based Compensation

During the first quarter of 2010, Edison International granted its 2010 stock-based compensation awards to SCE employees, which included stock options, performance shares and restricted stock units. SCE's total stock-based compensation expenses (reflected in the caption "Operation and maintenance" on the consolidated statements of income) was $6 million for both the three months ended September 30, 2010 and 2009, and $16 million and $15 million for the nine months ended September 30, 2010 and 2009, respectively. The income tax benefit recognized in the consolidated statements of income was $2 million for both the three months ended September 30, 2010 and 2009, and $6 million for both the nine months ended September 30, 2010 and 2009. Excess tax benefits included in "Settlements of stock-based compensation – net" in the financing section of the consolidated statements of cash flows were $3 million and $6 million for the nine months ended September 30, 2010 and 2009, respectively.

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
	(Unaudited)
Outstanding at December 31, 2009		8,749,015		$	31.91
Granted		2,157,031			33.28
Expired		(2,688	)		51.38
Forfeited		(78,641	)		31.50
Exercised		(396,184	)		23.02
Affiliate transfers – net		28,554			36.33
Outstanding at September 30, 2010		10,457,087			32.54		6.52
Vested and expected to vest at September 30, 2010		10,170,748			32.55		6.46	$	54,894,724
Exercisable at September 30, 2010		5,599,849			32.79		4.79	$	35,092,633

SCE's cash outflows to purchase Edison International shares in the open market to settle stock options exercised were $5 million and $2 million for the three months ended September 30, 2010 and 2009, respectively, and $12 million and $6 million for the nine months ended September 30, 2010 and 2009, respectively. Cash inflows from participants to exercise stock options were $3 million and $1 million for the three months ended September 30, 2010 and 2009, respectively, and $8 million and $4 million for the nine months ended September 30, 2010 and 2009, respectively. The tax benefit realized from options exercised was $1 million and less than $1 million for the three months ended September 30, 2010 and 2009, respectively, and $2 million and $1 million for the nine months ended September 30, 2010 and 2009, respectively.

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Performance Shares

The following is a summary of the status of Edison International nonvested performance shares granted to SCE employees:

	Equity Awards					Liability Awards
	Shares			Weighted-Average Grant Date Fair Value		Shares			Weighted-Average Fair Value1
	(Unaudited)
Nonvested at December 31, 2009		172,604		$	36.65		172,604
Granted		82,056			31.96		82,056
Forfeited		(34,673	)		55.87		(34,673	)
Affiliate transfers – net		791			41.62		791
Nonvested at September 30, 2010		220,778			32.06		220,778		$	16.47

¹

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

There were no performance shares paid in 2009 or 2010.

Note 6. Commitments and Contingencies

Lease Commitments

SCE entered into two 20-year power purchase contracts which are classified as capital leases and are expected to be recorded on the consolidated balance sheets upon commencement of the contracts in 2012 and 2013. SCE's commitments upon commencement are estimated to be: $38 million in 2012, $98 million in 2013, $120 million in 2014, and $2.1 billion for the period remaining thereafter (amounts representing executory costs and interest are $490 million and $911 million, respectively).

Other Commitments

At September 30, 2010, SCE had power purchase contracts with additional commitments estimated to be: $30 million for the remainder of 2010, $94 million in 2011, $77 million in 2012, $53 million in 2013, $49 million in 2014, and $1 billion for the period remaining thereafter.

In October 2010, SCE completed its 2010 annual request for offers and entered into new power purchase contracts with commitments estimated to be: $35 million in 2011, $122 million in 2012, $163 million in 2013, and $69 million in 2014.

SCE has letters of credit outstanding under a credit facility. For further discussion, see Note 3.

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.

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

Contingencies

In addition to the matters disclosed in these Notes, SCE is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business.

Environmental Developments

SCE is subject to numerous environmental laws and regulations, which typically require a lengthy and complex process for obtaining licenses, permits and approvals and require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.

Possible developments, such as the enactment of more stringent environmental laws and regulations, proceedings that may be initiated by environmental and other regulatory authorities, cases in which new theories of liability are recognized, and settlements agreed to by other companies that establish precedent or expectations for the power industry, could affect the costs and the manner in which business is conducted, and could cause substantial additional capital expenditures or operational expenditures or the ceasing of operations at certain facilities. There is no assurance that any additional costs arising from such developments would be recovered from customers or that SCE's financial position, results of operations and cash flows would not be materially affected by such developments.

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California Renewable Energy Developments

In September 2010, CARB voted to adopt a Renewable Electricity Standard regulation, which would require most retail sellers of electricity in California to procure 33% of their electricity from eligible renewable energy resources by 2020. The potential impact of the Standard will depend on provisions, which have not yet been finalized, and therefore remains uncertain. SCE believes that achieving a 33% renewables portfolio standard in this timeframe will be highly ambitious, given the magnitude of the infrastructure build-out required and the slow pace of transmission permitting and approvals.

Greenhouse Gas Regulation

In June 2010, the US EPA finalized the Prevention of Significant Deterioration ("PSD") and Title V greenhouse gas tailoring rule. The effective date of the final rule is August 2, 2010. The emissions thresholds for CO₂ equivalents in the final rule are as follows:

January – June 2011	75,000 tons per year for new and modified sources already subject to PSD for pollutants other than greenhouse gases
July 2011 – June 2013	100,000 tons per year for new sources, and 75,000 tons per year for modified sources

Numerous legal challenges to the greenhouse gas tailoring rule have been filed. As written, the rule applies to all sources meeting the thresholds that are built or modified after January 1, 2011. If controls are required to be installed at SCE's facilities in the future in order to reduce greenhouse gas emissions pursuant to regulations issued by the US EPA or others, the potential impact will depend on the nature of the controls applied, which remains uncertain.

Once-Through Cooling

In May 2010, the California State Water Resources Board issued a final policy, which establishes closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like San Onofre and many of the existing fossil-fueled power plants along the California coast. The final policy requires an independent engineering study to be completed prior to the fourth quarter of 2013 regarding the feasibility of compliance by California's two coastal nuclear power plants. Depending on the results of the study, the required compliance may result in significant capital expenditures at San Onofre and may affect its operations. The policy may also significantly impact SCE's ability to procure generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems, system reliability and the cost of electricity to the extent other coastal power plants in California are forced to shut down or limit operations. The policy has the potential to adversely affect California's nineteen once-through cooled power plants, which provide over 21,000 MW of combined, in-state generation capacity, including over 9,100 MW of capacity interconnected within SCE's service territory.

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,

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

As of September 30, 2010, SCE's recorded estimated minimum liability to remediate its 23 identified sites was $38 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 sites could exceed its recorded liability by up to $228 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 34 immaterial sites for which total liability ranges from $5 million (the recorded minimum liability) to $10 million.

The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $34 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $39 million for its estimated minimum environmental cleanup costs expected to be recovered through customer rates.

SCE's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination and the extent, if any, that SCE may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $3 million to $18 million. Recorded costs were $3 million and $2 million for the three months ended September 30, 2010 and 2009, respectively, and $7 million for both the nine months ended September 30, 2010 and 2009.

Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental remediation costs, SCE believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

Federal and State Income Taxes

SCE and its subsidiaries are included in Edison International's consolidated federal income tax and combined state franchise tax returns. Edison International's consolidated federal income tax returns are currently under examination by the IRS for tax years 2003 through 2006 and are subject to examination through tax year 2009. Edison International's combined California state franchise tax returns are subject to examination for tax years 1991 through 2009. For further discussion, see Note 4.

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2010 FERC Rate Case

In September 2009, the FERC issued an order allowing SCE to implement its proposed 2010 rates effective March 1, 2010, subject to refund. The proposed rates would increase SCE's FERC revenue requirement by $107 million, or 24%, over the 2009 FERC revenue requirement primarily due to an increase in transmission rate base, and would result in an approximate 1% increase to SCE's overall system average rate. SCE has terminated settlement negotiations and begun the litigation process for the proposed 2010 rates. A final decision is expected in the second half of 2011.

FERC Transmission Incentives and CWIP Proceedings

In November 2007, the FERC issued an order granting ROE incentive adders, recovery of the ROE and incentive adders in the CWIP proceedings, and 100% recovery of abandoned plant costs (if any) for three of SCE's transmission projects. The current ROE incentive adders are: 100 basis point adder for DCR, 125 basis point adder for Tehachapi, and 75 basis point adder for Rancho Vista. The CPUC filed an appeal of the November order, which had been stayed pending final resolution by the FERC of the 2008 CWIP proceeding. In April 2010, the FERC issued an order on SCE's 2008 CWIP proceeding. The order sets SCE's 2008 base ROE (before incentives) at 9.54% and establishes a methodology for determining the base ROE for 2009 and 2010 CWIP incentives. In May 2010, SCE filed an application for rehearing with the FERC. The order did not have a material impact on SCE's earnings or cash flows. The collected 2008 through 2010 CWIP revenue requirements are subject to refund, pending a final FERC order on these matters.

Navajo Nation Litigation

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

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

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contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $43 million per year. Insurance premiums are charged to operating expense.

Spent Nuclear Fuel

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

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

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Note 7. Consolidated Statements of Changes in Equity

The following table provides changes in equity for the nine months ended September 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
	(Unaudited)
Balance at December 31, 2009	$	2,168	$	551	$	(19	)	$	4,746		$	920	$	349		$	8,715
Net income		—		—		—			897			—		—			897
Other comprehensive income		—		—		2			—			—		—			2
Deconsolidation of variable interest entities (see Note 12)		—		—		—			—			—		(349	)		(349	)
Dividends declared on common stock		—		—		—			(100	)		—		—			(100	)
Dividends declared on preferred and preference stock not subject to mandatory redemption		—		—		—			(39	)		—		—			(39	)
Stock-based compensation – net		—		3		—			(5	)		—		—			(2	)
Noncash stock-based compensation and other		—		12		—			(3	)		—		—			9
Balance at September 30, 2010	$	2,168	$	566	$	(17	)	$	5,496		$	920	$	—		$	9,133

The following table provides changes in equity for the nine months ended September 30, 2009.

	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
	(Unaudited)
Balance at December 31, 2008	$	2,168	$	532	$	(14	)	$	3,827		$	920	$	380		$	7,813
Net income		—		—		—			1,091			—		90			1,181
Other comprehensive income		—		—		1			—			—		—			1
Distributions to noncontrolling interests		—		—		—			—			—		(94	)		(94	)
Dividends declared on common stock		—		—		—			(200	)		—		—			(200	)
Dividends declared on preferred and preference stock not subject to mandatory redemption		—		—		—			(38	)		—		—			(38	)
Stock-based compensation – net		—		6		—			(2	)		—		—			4
Noncash stock based compensation and other		—		10		—			(3	)		—		—			7
Balance at September 30, 2009	$	2,168	$	548	$	(13	)	$	4,675		$	920	$	376		$	8,674

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Note 8. Supplemental Cash Flows Information

The following is SCE's supplemental cash flows information:

		Nine Months Ended September 30,
(in millions)		2010			2009
		(Unaudited)
Cash payments (receipts) for interest and taxes
	Interest – net of amounts capitalized	$	339		$	326
	Tax receipts		(309	)		(690	)
Noncash investing and financing activities
	Details of debt exchange:
	Pollution-control bonds redeemed	$	(303	)	$	—
	Pollution-control bonds issued		303			—
	Deconsolidation of variable interest entities:
	Assets other than cash	$	306		$	—
	Liabilities and noncontrolling interests		(398	)		—
Dividends declared but not paid
	Common stock	$	—		$	100
	Preferred and preference stock		9			8

Note 9. 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 for a liability should reflect the entity's nonperformance risk. Fair value is determined using a hierarchy to prioritize the inputs to valuation models. 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 three levels of the fair value hierarchy are:

Level 1 – Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets and liabilities;

Level 2 – Pricing inputs that 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; and

Level 3 – Prices or valuations that require inputs that are both significant to the fair value measurements and unobservable.

SCE's assets and liabilities carried at fair value primarily consist of derivative contracts, nuclear decommissioning trust investments and money market funds. Derivative contracts are primarily commodity contracts for the purchase and sale of power and gas and include contracts for forward physical sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange or over-the-counter traded.

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The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities, and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. Investments in money market funds are generally classified as Level 1, as fair value is determined by observable market prices in active markets. SCE's Level 2 derivatives primarily consist of natural gas financial swaps and natural gas physical trades for which SCE obtains the applicable Henry Hub, basis, index, or forward market prices from the New York Mercantile Exchange and Intercontinental Exchange.

Level 3 includes the majority of SCE's derivatives, including over-the-counter options, bilateral contracts, capacity contracts, and QF contracts. The fair value of these derivatives 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.

Level 3 also includes derivatives that trade infrequently (such as CRRs in the California market and over-the-counter derivatives at illiquid locations) and long-term power agreements. For illiquid CRRs, objective criteria are reviewed, including system congestion and other underlying drivers, and fair value is adjusted when it is concluded that a change in objective criteria would result in a new valuation that better reflects fair value.

Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a 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. 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 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. Derivative contracts with counterparties that have significant nonperformance risk are classified as Level 3.

The fair value of the derivative assets and liabilities are adjusted for nonperformance risk. To assess nonperformance risk, SCE considers default risk and the loss incurred if a counterparty defaults. The fair value of derivative assets and derivative liabilities nonperformance risks was $1 million and $9 million, respectively at September 30, 2010 and was $2 million and $7 million, respectively, at December 31, 2009.

The 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.

22

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

			As of September 30, 2010
(in millions)			Level 1		Level 2			Level 3			Netting and Collateral1		Total
			(Unaudited)
Assets at Fair Value
	Money market funds2		$	825	$	—		$	—		$	—	$	825
	Derivative contracts:
		Electricity		—		3			—			—		3
		Natural Gas		—		65			16			—		81
		CRRs		—		—			177			—		177
		Subtotal of derivative contracts		—		68			193			—		261
	Long-term disability plan			9		—			—			—		9
	Nuclear decommissioning trusts:
		Stocks3		1,840		—			—			—		1,840
		Municipal bonds		—		733			—			—		733
		Corporate bonds4		—		418			—			—		418
		U.S. government and agency securities		260		60			—			—		320
		Short-term investments, primarily cash equivalents5		3		13			—			—		16
		Subtotal of nuclear decommissioning trusts		2,103		1,224			—			—		3,327
Total assets6			$	2,937	$	1,292		$	193		$	—	$	4,422
Liabilities at Fair Value
	Derivative contracts:
		Electricity	$	—	$	—		$	(75	)	$	—	$	(75	)
		Natural Gas		—		(320	)		(18	)		5		(333	)
		Tolling		—		—			(1,115	)		—		(1,115	)
		Subtotal of derivative contracts		—		(320	)		(1,208	)		5		(1,523	)
Net assets (liabilities)			$	2,937	$	972		$	(1,015	)	$	5	$	2,899

23

			As of December 31, 2009
(in millions)			Level 1		Level 2			Level 3			Netting and Collateral1		Total
			(Unaudited)
Assets at Fair Value
	Money market funds2		$	360	$	—		$	—		$	—	$	360
	Derivative contracts:
		Electricity		—		—			1			—		1
		Natural Gas		—		10			76			—		86
		CRRs		—		—			217			—		217
		Tolling		—		—			43			—		43
		Subtotal of derivative contracts		—		10			337			—		347
	Long-term disability plan			8		—			—			—		8
	Nuclear decommissioning trusts:
		Stocks3		1,772		—			—			—		1,772
		Municipal bonds		—		634			—			—		634
		Corporate bonds4		—		393			—			—		393
		U.S. government and agency securities		240		68			—			—		308
		Short-term investments, primarily cash equivalents5		1		14			—			—		15
		Subtotal of nuclear decommissioning trusts		2,013		1,109			—			—		3,122
Total assets6			$	2,381	$	1,119		$	337		$	—	$	3,837
Liabilities at Fair Value
	Derivative contracts:
		Electricity	$	—	$	—		$	(25	)	$	—	$	(25	)
		Natural Gas		—		(150	)		(21	)		—		(171	)
		Tolling		—		—			(402	)		—		(402	)
		Subtotal of derivative contracts		—		(150	)		(448	)		—		(598	)
Net assets (liabilities)			$	2,381	$	969		$	(111	)	$	—	$	3,239

¹

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

²

Included in cash and cash equivalents on SCE's consolidated balance sheet.

³

At September 30, 2010 and December 31, 2009, approximately 67% of the equity investments were located in the United States.

⁴

Corporate bonds are diversified. At September 30, 2010 and December 31, 2009, this category included $38 million and $50 million, respectively, for collateralized mortgage obligations and other asset backed securities.

⁵

Excludes net assets of $20 million and $18 million of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases at September 30, 2010 and December 31, 2009, respectively.

⁶

Excludes $31 million and $32 million of cash surrender value of life insurance investments for deferred compensation at September 30, 2010 and December 31, 2009, respectively.

24

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

		Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)		2010			2009			2010			2009
		(Unaudited)
Fair value of derivative contracts, net asset (liability) at beginning of period		$	(869	)	$	117		$	(111	)	$	(518	)
Total realized/unrealized gains (losses):
	Included in earnings		—			—			—			—
	Included in regulatory assets and liabilities1		(142	)		(322	)		(924	)		270
Purchases and settlements, net			12			5			36			48
Transfers into Level 3			—			—			—			—
Transfers out of Level 3			(16	)		25			(16	)		25
Fair value, net liability at end of period		$	(1,015	)	$	(175	)	$	(1,015	)	$	(175	)
Change during the period in unrealized gains (losses) related to assets and liabilities held at the end of period		$	(160	)	$	(319	)	$	(883	)	$	302

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 of transfers in and out of each level at the end of each reporting period. There were no significant transfers between levels during 2010 and 2009.

Nuclear Decommissioning Trusts

SCE is collecting in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent decommissioning trusts. Contributions are approximately $31 million per year. Funds collected, together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.

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

		Amortized Cost				Fair Value
(in millions)	Maturity Dates1	September 30, 2010		December 31, 2009		September 30, 2010		December 31, 2009
		(Unaudited)
Stocks	–	$	848	$	822	$	1,840	$	1,772
Municipal bonds	2010 – 2049		618		545		733		634
Corporate bonds	2010 – 2044		327		309		418		393
U.S. government and agency securities	2010 – 2040		284		287		320		308
Short-term investments and receivables/payables	2010		34		33		36		33
Total		$	2,111	$	1,996	$	3,347	$	3,140

¹

Maturity dates as of September 30, 2010.

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 $302 million and $503 million for the three months ended September 30, 2010 and 2009, respectively and $902 million and $1.8 billion for the nine months ended September 30, 2010 and 2009, respectively. Unrealized

25

holding gains, net of losses, were $1.2 billion and $1.1 billion at September 30, 2010 and December 31, 2009, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible.

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

		Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)		2010			2009			2010			2009
		(Unaudited)
Balance at beginning of period		$	3,083		$	2,673		$	3,140		$	2,524
	Realized gains		14			35			52			223
	Realized losses		—			(3	)		(4	)		(142	)
	Unrealized gains (losses) – net		233			296			90			444
	Other-than-temporary impairment		(5	)		(2	)		(16	)		(105	)
	Interest, dividends, contributions and other		22			26			85			81
Balance at end of period		$	3,347		$	3,025		$	3,347		$	3,025

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

Long-term Debt

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

	September 30, 2010				December 31, 2009
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Unaudited)
Long-term debt, including current portion	$	7,626	$	8,740	$	6,740	$	7,202

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 approximate fair value and therefore are not included in the table above.

26

Note 10. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)		September 30, 2010		December 31, 2009
		(Unaudited)
Current:
	Regulatory balancing accounts	$	207	$	94
	Energy derivatives		197		25
	Other		—		1
			404		120
Long-term:
	Regulatory balancing accounts		52		43
	Deferred income taxes – net		1,838		1,561
	Unamortized nuclear investment – net		301		340
	Nuclear-related ARO investment – net		243		258
	Unamortized coal plant investment – net		70		73
	Unamortized loss on reacquired debt		273		287
	Pensions and other postretirement benefits		999		1,014
	Energy derivatives		1,201		357
	Environmental remediation		39		36
	Other		211		170
			5,227		4,139
Total regulatory assets		$	5,631	$	4,259

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)		September 30, 2010		December 31, 2009
		(Unaudited)
Current:
	Regulatory balancing accounts	$	798	$	363
	Other		6		4
			804		367
Long-term:
	Regulatory balancing accounts		846		642
	ARO		220		171
	Costs of removal		2,597		2,515
			3,663		3,328
Total regulatory liabilities		$	4,467	$	3,695

27

Note 11. Other Income and Expenses

Other income and expenses are as follows:

		Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)		2010		2009		2010		2009
		(Unaudited)
Other Income:
	Equity AFUDC	$	24	$	60	$	76	$	95
	Increase in cash surrender value of life insurance policies		7		4		19		17
	Other		2		5		8		14
Total other income		$	33	$	69	$	103	$	126
Other Expenses:
	Civic, political and related activities and donations	$	7	$	11	$	21	$	19
	Marketing services		2		1		5		6
	Other		1		1		13		8
Total other expenses		$	10	$	13	$	39	$	33

In July 2009, the Mountainview power plant was transferred to utility rate base pursuant to CPUC and FERC approvals which resulted in recognition of $50 million in Equity AFUDC during the three- and nine-month periods ended September 30, 2009.

Note 12. Variable Interest Entities

Effective January 1, 2010, SCE adopted the FASB's new guidance regarding variable interest entities ("VIEs"). A 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 new guidance replaces the predominantly quantitative model for determining which reporting entity, if any, has a controlling financial interest in a VIE with a qualitative approach. Under this new qualitative model, 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 unless specific exceptions or exclusions are met. 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 Interests in VIEs that are not Consolidated

Power Purchase Contracts

SCE has power purchase agreements ("PPAs") in which SCE has a variable interest in 17 VIEs, including 6 tolling agreements, where SCE provides the natural gas to operate the plants, and 11 contracts with QFs (including the Big 4 projects) 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

28

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. SCE does not have control over the operation and maintenance of the facilities considered VIEs and it does not bear operational risk of the facilities. See further discussion of the Big 4 projects below.

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, which are accounted for at fair value. See Note 9 for a discussion on nonperformance risk. Further, 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 6. The aggregate capacity dedicated to SCE for these VIE projects was 4,045 MW at September 30, 2010 and the amounts that SCE paid to these projects were $205 million and $184 million for the three months ended September 30, 2010 and 2009, respectively, and $447 million and $414 million for the nine months ended September 30, 2010 and 2009, respectively. These amounts are recoverable in customer rates.

The following table summarizes as of September 30, 2010, SCE's assets and liabilities and exposure to loss associated with SCE's variable interests in the VIEs described above:

	Assets				Liabilities
(in millions)	Short- Term		Long- Term		Short- Term		Long- Term		Maximum Exposure
	(Unaudited)
Derivatives	$	—	$	—	$	50	$	1,064	$	—
Accounts payable		—		—		63		—		—
Total	$	—	$	—	$	113	$	1,064	$	—

The following table summarizes as of December 31, 2009, SCE's assets and liabilities and exposure to loss associated with SCE's variable interests in the VIEs described above:

	Assets				Liabilities
(in millions)	Short- Term		Long- Term		Short- Term		Long- Term		Maximum Exposure
	(Unaudited)
Derivatives	$	—	$	43	$	17	$	385	$	43
Accounts payable		—		—		39		—		—
Total	$	—	$	43	$	56	$	385	$	43

Realized and unrealized losses are recovered or expected to be recovered from ratepayers in rates, subject to reasonableness review, and therefore are not reflected in earnings.

Big 4 Projects Consolidated Prior to 2010

SCE has variable interests in the Big 4 Projects through power contracts between SCE and the Big 4 Projects containing variable contract pricing provisions based on the price of natural gas. Prior to 2010, SCE had determined that it was the primary beneficiary of these four VIEs and, therefore,

29

consolidated these projects. SCE prospectively deconsolidated the Big 4 Projects at January 1, 2010 since it did not control the commercial and operating activities of these projects. The deconsolidation did not result in a gain or loss.

SCE's consolidated balance sheet captions impacted by VIE activities prior to 2010 are presented below:

	December 31, 2009
(in millions)	Electric Utility		VIEs		Eliminations			SCE
	(Unaudited)
Cash and equivalents	$	370	$	92	$	—		$	462
Accounts receivable – net		689		62		(32	)		719
Inventory		321		16		—			337
Other current assets		94		3		—			97
Nonutility property – net of accumulated depreciation		71		253		—			324
Other long-term assets		318		4		—			322
Total assets		32,076		430		(32	)		32,474
Accounts payable	$	1,031	$	59	$	(32	)	$	1,058
Other current liabilities		632		5		—			637
Asset retirement obligations		3,181		17		—			3,198
Noncontrolling interest		—		349		—			349
Total liabilities and equity		32,076		430		(32	)		32,474

SCE's consolidated statements of income impacted by VIE activities prior to 2010 are presented below:

		Three Months Ended September 30, 2009
(in millions)		Electric Utility			VIEs			Eliminations			SCE
		(Unaudited)
Operating revenue		$	3,021		$	166		$	(118	)	$	3,069
Fuel			97			80			—			177
Purchased power			1,150			—			(118	)		1,032
Operation and maintenance			780			22			—			802
Depreciation, decommissioning and amortization			294			8			—			302
Property and other taxes			60			—			—			60
Total operating expenses			2,381			110			(118	)		2,373
Operating income			640			56			—			696
Interest income			4			—			—			4
Other income			69			—			—			69
Interest expense – net of amounts capitalized			(105	)		—			—			(105	)
Other expenses			(13	)		—			—			(13	)
Income tax benefit			(236	)		—			—			(236	)
Net income			359			56			—			415
Less: Net income attributable to noncontrolling interest			—			(56	)		—			(56	)
	Dividends on preferred and preference stock not subject to mandatory redemption		(13	)		—			—			(13	)
Net income available for common stock		$	346		$	—		$	—		$	346

30

		Nine Months Ended September 30, 2009
(in millions)		Electric Utility			VIEs			Eliminations			SCE
		(Unaudited)
Operating revenue		$	7,377		$	440		$	(286	)	$	7,531
Fuel			276			257			—			533
Purchased power			2,441			—			(286	)		2,155
Operation and maintenance			2,154			68			—			2,222
Depreciation, decommissioning and amortization			852			25			—			877
Property and other taxes			187			—			—			187
Gain on sale of assets			(1	)		—			—			(1	)
Total operating expenses			5,909			350			(286	)		5,973
Operating income			1,468			90			—			1,558
Interest income			9			—			—			9
Other income			126			—			—			126
Interest expense – net of amounts capitalized			(320	)		—			—			(320	)
Other expenses			(33	)		—			—			(33	)
Income tax benefit			(159	)		—			—			(159	)
Net income			1,091			90			—			1,181
Less: Net income attributable to noncontrolling interest			—			(90	)		—			(90	)
	Dividends on preferred and preference stock not subject to mandatory redemption		(38	)		—			—			(38	)
Net income available for common stock		$	1,053		$	—		$	—		$	1,053

31

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

FORWARD-LOOKING STATEMENTS

This MD&A 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, or that otherwise could impact SCE or its subsidiaries, include, but are not limited to:

•

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;

•

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;

•

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;

•

risks associated with operating nuclear and other power generating facilities, including operating risks; nuclear fuel storage issues; failure, availability, efficiency, output, cost of repairs and retrofits in each case of equipment; and availability and cost of spare parts;

•

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;

32

•

cost and availability of labor, equipment and materials;

•

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

•

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

•

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

•

potential for penalties or disallowances caused by noncompliance with applicable laws and regulations;

•

outcome of disputes with the IRS and other tax authorities regarding tax positions taken by Edison International;

•

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

•

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

•

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

•

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

•

weather conditions and natural disasters;

•

risks inherent in the development of generation projects and transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, financing, 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, are discussed throughout this MD&A and in the "Risk Factors" section included in Part I, Item 1A of the 2009 Form 10-K. Readers are urged to read this entire report, including the information incorporated by reference, 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 Securities and Exchange Commission.

This MD&A for the three- and nine-month periods ended September 30, 2010 discusses material changes in the consolidated financial condition, results of operations and other developments of SCE since December 31, 2009, and as compared to the three- and nine-month periods ended September 30, 2009. This discussion presumes that the reader has read or has access to SCE's MD&A for the calendar year 2009 (the "year-ended 2009 MD&A"), which was included in the 2009 Form 10-K.

33

MANAGEMENT OVERVIEW

Introduction

This overview is presented in four sections:

•

Highlights of operating results,

•

SCE capital program,

•

SCE 2012 General Rate Case, and

•

Environmental developments.

The overview is presented as an update to the overview presented in the 2009 Form 10-K. See pages 31 to 34 of the 2009 Form 10-K for additional information on these topics.

Highlights of Operating Results

		Three Months Ended September 30,							Nine Months Ended September 30,
(in millions)		2010		2009		Change			2010			2009		Change
Net income available for common stock		$	394	$	346	$	48		$	858		$	1,053	$	(195	)
Non-Core Earnings (Loss)
	Global Settlement		42		—		42			95			300		(205	)
	Tax impact of health care legislation		—		—		—			(39	)		—		(39	)
	Regulatory items		—		46		(46	)		—			46		(46	)
Core Earnings		$	352	$	300	$	52		$	802		$	707	$	95

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

SCE's 2010 core earnings increased $52 million and $95 million for the quarter and year-to-date, respectively. The quarter increase was primarily due to higher authorized revenue to support rate base growth and higher capitalized financing costs (AFUDC). The year-to-date increase was due to higher authorized revenue to support rate base growth, lower income tax expense and higher capitalized financing costs (AFUDC). The year-to-date increase was partially offset by higher operating expenses that continue to reflect the impact of curtailed spending last year due to the timing of the 2009 CPUC GRC decision. The year-to-date lower tax expense includes a change in method of tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program.

34

Consolidated non-core items for SCE included:

•

An earnings benefit of $95 million recorded in 2010 relating to the California impact of the federal Global Settlement, including $53 million in the second quarter resulting from acceptance by the Franchise Tax Board of the tax positions finalized with the IRS in 2009 and $42 million in the third quarter resulting from receipt of the final interest determination from the Franchise Tax Board. During the nine months ended September 30, 2009, SCE recognized a $300 million earnings benefit related to the federal Global Settlement finalized with the IRS (described in "Item 8. SCE Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K).

•

A non-cash charge of $39 million recorded in the first quarter of 2010 to reverse previously recognized federal tax benefits eliminated by the federal health care legislation. The Patient Protection and Affordable Care Act, as modified by the Health Care and Education Reconciliation Act, was enacted in March 2010. The new health care legislation includes a provision that eliminates the federal tax deduction of retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.

•

An after-tax benefit of $46 million recorded in the third quarter of 2009 resulting from the transfer of the Mountainview power plant to utility rate base pursuant to CPUC and FERC approvals.

SCE Capital Program

SCE's capital program continues to be focused primarily in five areas:

•

Upgrading and constructing new transmission lines to strengthen system reliability and increase access to renewable energy, including the Tehachapi, Devers-Colorado River and Eldorado-Ivanpah projects.

•

Maintaining reliability and expanding capability of SCE's transmission and distribution system.

•

Developing and installing up to 250 MW of utility-owned solar photovoltaic generating facilities (generally ranging in size from 1 to 2 MW each) on commercial and industrial rooftops and other space in SCE's service territory.

•

Replacing steam generators at San Onofre intended to enable operations until at least the end of its initial license period in 2022. During the first quarter of 2010, SCE completed the replacement of the steam generators at San Onofre Unit 2, which was subsequently returned to service on April 11, 2010. In October 2010, SCE began the process of installing the final two steam generators at San Onofre Unit 3 which are expected to be placed in service in early 2011. See "Results of Operations—Electric Utility Results of Operations—Utility Earning Activities" for discussion of the extended outage at San Onofre Unit 2.

•

Installing "smart" meters in approximately 5.3 million households and small businesses, which is referred to as EdisonSmartConnect™. During the first nine months of 2010, SCE installed approximately 1.4 million smart meters, with cumulative installations totaling over 1.5 million.

SCE plans to utilize cash generated from its operations and issuance of additional debt and preferred equity for its capital program. During the nine months ended September 30, 2010, SCE issued long-term debt of $1.1 billion to fund its capital program (see "Liquidity and Capital Resources—Historical Consolidated Cash Flows—Condensed Consolidated Statement of Cash Flows—Cash Flows Provided (Used) by Financing Activities" for further information).

35

SCE's capital investments (including accruals) during the nine months ended September 30, 2010 totaled $2.4 billion. SCE projects that capital investments will be in the range of $3.3 billion to $4.0 billion in 2010 and in the range of $18 billion to $21.5 billion for 2010 – 2014. The rate of actual capital spending will be affected by permitting, regulatory, market and other factors as discussed further under "Liquidity and Capital Resources—Capital Investment Plan" in the 2009 Form 10-K.

2012 General Rate Case

On July 19, 2010, SCE submitted to the CPUC's Division of Ratepayer Advocates its notice of intent ("NOI") to file a 2012 GRC. The NOI indicates that SCE's GRC application, expected to be filed by year-end 2010, will request a 2012 base rate revenue requirement of $6.3 billion. After considering the effects of sales growth, SCE's request would be a $903 million increase over projected 2011 base rate revenue. If the CPUC approves the requested rate increase and allocates the increase to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 16.9% and 7.9%, respectively. The requested revenue requirement increase is driven by the need to maintain system reliability, accommodate customer load growth, and increase operation and maintenance expenses primarily for capital-related projects, information technology, insurance and pension contributions. The NOI also indicates that SCE's application will propose a post-test year ratemaking mechanism which would result in 2013 and 2014 incremental base revenue requirement increases, net of sales growth, of $305 million and $542 million, respectively, for the same reasons. The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted.

Environmental Developments

For a discussion of environmental regulation developments regarding Greenhouse Gas Regulation, California Renewable Electricity Standard, and California Once-Through Cooling Policy, see "SCE Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Environmental Developments."

RESULTS OF OPERATIONS

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

•

Utility earning activities, which mainly represent CPUC- and FERC-authorized base rates, which allow a reasonable return, and CPUC-authorized incentive mechanisms; and

•

Utility cost-recovery activities, which mainly represent CPUC-authorized balancing accounts, which allow recovery of costs incurred (including carrying costs) or provide mechanisms to track and recover or refund differences in forecasted and actual amounts. Balancing accounts (except for certain capital-related projects) do not allow for a return.

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 and taxes on capital projects recovered through balancing account mechanisms. Differences between authorized 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.

36

Utility cost-recovery activities include rates which provide for recovery, subject to reasonableness review, of fuel costs, purchased power costs, certain operation and maintenance expenses (including public purpose related program costs), and depreciation expense related to certain projects. There is no return earned on cost-recovery expenses.

Electric Utility Results of Operations

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

Three Months Ended September 30, 2010 versus September 30, 2009

		Three Months Ended September 30, 2010								Three Months Ended September 30, 2009
(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities1,2		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities1,2		Total Consolidated
Operating revenue		$	1,601		$	1,497	$	3,098		$	1,494		$	1,575	$	3,069
Fuel and purchased power			—			1,218		1,218			—			1,209		1,209
Operation and maintenance			541			262		803			506			296		802
Depreciation, decommissioning and amortization			300			16		316			288			14		302
Property and other taxes			64			1		65			60			—		60
Total operating expenses			905			1,497		2,402			854			1,519		2,373
Operating income			696			—		696			640			56		696
Net interest expense and other			(84	)		—		(84	)		(45	)		—		(45	)
Income before income taxes			612			—		612			595			56		651
Income tax expense			205			—		205			236			—		236
Net income			407			—		407			359			56		415
Net income attributable to noncontrolling interests			—			—		—			—			56		56
Dividends on preferred and preference stock not subject to mandatory redemption			13			—		13			13			—		13
Net income available for common stock		$	394		$	—	$	394		$	346		$	—	$	346
Core Earnings3							$	352							$	300
Non-Core Earnings:
	Global Settlement							42								—
	Regulatory items4							—								46
Total SCE GAAP Earnings							$	394							$	346

¹

Effective January 1, 2010, SCE deconsolidated the Big 4 projects which affects comparability of cost-recovery activities (see "SCE Notes to Consolidated Financial Statements Note 12. Variable Interest Entities" for further discussion). Included in the

37

three- and nine-month periods ended September 30, 2009, respectively, were the following amounts (including elimination entries) related to the Big 4 projects:

(in millions)	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Operating revenue	$	48		$	154
Fuel		80			257
Purchased power		(118	)		(286	)
Operation and maintenance		22			68
Depreciation		8			25
Total operating expenses		(8	)		64
Net income	$	56		$	90

²

Effective July 1, 2009, SCE transferred Mountainview Power Company, LLC to SCE (see "Note 8. Property and Plant" in the 2009 Form 10-K for further discussion). As a result of the transfer and for comparability purposes, Mountainview's 2009 activities (zero for both operating revenue and total expenses for the three months ended September 30, 2009 and $49 million for both operating revenue and total expenses for the nine months ended September 30, 2009) were reclassified from cost-recovery activities to utility earning activities consistent with the 2010 regulatory recovery mechanism.

³

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

⁴

The $46 million non-core earnings benefit related to the transfer of the Mountainview power plant to utility rate base in the third quarter of 2009 is reflected in the following captions: operating revenue of $(13) million; operation and maintenance of $(14) million; depreciation expense of $7 million; net interest expense and other of $50 million; and an income tax benefit of $2 million.

Utility Earning Activities

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $107 million primarily due to an increase related to implementation of the 2009 GRC (effective January 1, 2009), which authorized a 4.25% increase in 2010 authorized revenue and an increase related to revenue requirements for capital projects recovered through CPUC-authorized balancing accounts primarily related to the steam generator replacement project and the EdisonSmartConnect^TM project.

•

Higher operation and maintenance expense of $35 million primarily resulting from higher transmission and distribution expenses primarily related to higher costs to support system reliability and infrastructure replacement and an increase in right of way costs.

•

Higher net interest expense and other of $39 million primarily related to a decrease in AFUDC-equity earnings due to the transfer of the Mountainview power plant to utility rate base in the third quarter of 2009, partially offset by a higher capitalized cost of equity (AFUDC) resulting from a higher capitalization rate and level of construction in progress. See "SCE Notes to Consolidated Financial Statements Note 11. Other Income and Expenses" for further detail of other income and expenses.

See "—Income Taxes" below for discussion of lower income taxes during the three months ended September 30, 2010 compared to the same period in 2009.

Utility Cost-Recovery Activities

Excluding the impact of deconsolidation of the Big 4 projects (see "SCE Notes to Consolidated Financial Statements Note 12. Variable Interest Entities"), utility cost-recovery activities were affected by lower purchased power expense of $32 million related to: lower realized losses of $60 million

38

reflecting the impact of higher natural gas prices and changes in SCE's hedge portfolio mix; and lower ISO-related and other energy costs of $45 million. These decreases were partially offset by: higher QF purchased power expense of $35 million primarily due to higher kWh purchases and higher natural gas prices; and higher bilateral energy purchase expense of $25 million, primarily resulting from a new contract.

Nine Months Ended September 30, 2010 versus September 30, 2009

		Nine Months Ended September 30, 2010									Nine Months Ended September 30, 2009
(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities1,2			Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities1,2			Total Consolidated
Operating revenue		$	4,175		$	3,329		$	7,504		$	3,951		$	3,580		$	7,531
Fuel and purchased power			—			2,612			2,612			—			2,688			2,688
Operation and maintenance			1,598			674			2,272			1,464			758			2,222
Depreciation, decommissioning and amortization			905			40			945			836			41			877
Property and other taxes			193			2			195			187			—			187
Gain on sale of assets			—			(1	)		(1	)		—			(1	)		(1	)
Total operating expenses			2,696			3,327			6,023			2,487			3,486			5,973
Operating income			1,479			2			1,481			1,464			94			1,558
Net interest expense and other			(244	)		(2	)		(246	)		(214	)		(4	)		(218	)
Income before income taxes			1,235			—			1,235			1,250			90			1,340
Income tax expense			338			—			338			159			—			159
Net income			897			—			897			1,091			90			1,181
Net income attributable to noncontrolling interests			—			—			—			—			90			90
Dividends on preferred and preference stock not subject to mandatory redemption			39			—			39			38			—			38
Net income available for common stock		$	858		$	—		$	858		$	1,053		$	—		$	1,053
Core Earnings3								$	802								$	707
Non-Core Earnings:
	Global Settlement								95									300
	Tax impact of health care legislation								(39	)								—
	Regulatory items4								—									46
Total SCE GAAP Earnings								$	858								$	1,053

¹

See footnote 1 under "—Three Months Ended September 30, 2010 versus September 30, 2009" table above.

²

See footnote 2 under "—Three Months Ended September 30, 2010 versus September 30, 2009" table above.

³

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

⁴

See footnote 4 under "—Three Months Ended September 30, 2010 versus September 30, 2009" table above.

Utility Earning Activities

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $224 million primarily due to the following:

•

$140 million increase related to implementation of the 2009 GRC (effective January 1, 2009), which authorized a 4.25% increase in 2010 authorized revenue.

39

•

$35 million increase related to the 2009 and 2010 FERC rate cases effective March 1, 2009 and March 1, 2010, respectively (see "Liquidity and Capital Resources—Regulatory Proceedings—2010 FERC Rate Case" for further discussion).

•

$30 million increase related to revenue requirements for capital projects recovered through CPUC-authorized balancing accounts primarily related to the steam generator replacement project and the EdisonSmartConnect^TM project.

•

Higher operation and maintenance expense of $134 million including the impact of curtailed spending last year due to the timing of the 2009 GRC decision. The increase in operation and maintenance expense was primarily in the following areas:

•

$60 million of higher transmission and distribution expenses. In addition to the impact of curtailed spending, the 2010 increase reflects higher costs to support system reliability and infrastructure replacement, increase in right of way costs, increases in preventive maintenance work costs, and line clearing costs.

•

$40 million of higher expenses related to higher general liability insurance, higher information technology costs, a nuclear insurance refund received in 2009, and higher injury and damage claims.

•

$15 million of higher generation expenses primarily resulting from a $10 million increase at San Onofre mostly due to additional work identified during the Unit 2 scheduled outage and a $10 million increase primarily due to overhaul and outage costs at Four Corners. These increases were partially offset by a $15 million hydrogen energy project payment made in the second quarter of 2009, which was subsequently approved for recovery through customer rates in December 2009. During the San Onofre Unit 2 scheduled outage, SCE identified and completed additional work unrelated to the steam generator replacement that resulted in increased operation and maintenance expense and extended the outage beyond SCE's initial estimated timeframe. San Onofre Unit 2 was subsequently returned to service on April 11, 2010.



The first two of the four replacement steam generators were installed in San Onofre Unit 2 in the first quarter of 2010. In October 2010, SCE began the process of installing the final two steam generators at San Onofre Unit 3 which are expected to be placed in service in early 2011. The CPUC has previously adopted a mechanism establishing thresholds for recovery of SCE's incurred costs for the steam generator replacements. Costs above an established threshold will require a reasonableness review. No cost recovery will be allowed for costs incurred that exceed an authorized cap. The determination of whether a reasonableness review of costs is necessary will be made after the steam generator replacement project is completed.


As discussed in the 2009 Form 10-K, the NRC has continued to affirm that San Onofre is being operated safely. However, SCE has had to address a number of regulatory and performance issues for which further corrective action is required to mitigate exposure to events that could have safety significance. In its 2010 mid-cycle performance review letter on September 1^st, the NRC noted that although San Onofre had developed corrective actions to resolve previously noted human performance and problem identification and resolution problems, the corrective actions that had been implemented had not been fully effective. The NRC is conducting additional inspections over its baseline program, including inspections to evaluate progress on these matters, and to assess actions taken to improve the working environment for employees to feel free to raise safety concerns. The NRC is also conducting additional public meetings to discuss these issues. SCE continues to implement plans to address the identified issues; however, a number of these issues remain outstanding, and additional issues continue to be identified. To address these regulatory and performance issues, SCE has applied increased management focus and other

40

resources to San Onofre, with an associated impact on operations and maintenance costs, as described in the 2009 Form 10-K. On September 2, 2010, SCE appointed a new Chief Nuclear Officer on an interim basis, pending the search for a permanent replacement. SCE anticipates that its corrective actions, and related additional management focus and operations and maintenance costs, will continue beyond 2010. If issues identified by the NRC remain uncorrected, these matters could have a material adverse effect on SCE.

•

Higher depreciation expense of $69 million primarily related to increased capital investments, including capitalized software costs.

•

Higher net interest expense and other of $30 million primarily related to a decrease in AFUDC-equity earnings due to the transfer of the Mountainview power plant to utility rate base in the third quarter of 2009, partially offset by a higher capitalized cost of equity (AFUDC) resulting from a higher capitalization rate and level of construction in progress.

See "—Income Taxes" below for discussion of higher income taxes during the nine-months ended September 30, 2010 compared to the same period in 2009.

Utility Cost-Recovery Activities

Excluding the impact of deconsolidation of the Big 4 projects (see "SCE Notes to Consolidated Financial Statements Note 12. Variable Interest Entities"), utility cost-recovery activities were primarily affected by:

•

Lower purchased power expense of $104 million related to: lower realized losses of $191 million reflecting the impact of higher natural gas prices and changes in SCE's hedge portfolio mix; and lower bilateral energy purchase expense of $70 million primarily due to decreased kWh purchases. These decreases were partially offset by: higher QF purchased power expense of $115 million primarily due to higher kWh purchases and higher natural gas prices; and higher ISO-related and other energy costs of $30 million, including replacement power costs related to the San Onofre Unit 2 scheduled outage.

•

Fuel expense reflects lower costs at Four Corners (coal) of $20 million primarily resulting from the planned outage and higher costs at Mountainview of $25 million resulting from higher natural gas prices.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account (over)/undercollections) was $3.4 billion and $7.8 billion for the three- and nine-month periods ended September 30, 2010, respectively, compared to $3.3 billion and $7.5 billion for the respective periods in 2009. The quarter and year-to-date increases reflect a rate increase of $312 million and $591 million, respectively, and a sales volume decrease of $226 million and $314 million, respectively. The rate increase was due to higher system average rates for 2010 compared to the same periods in 2009 mainly due to the implementation of the CPUC 2009 GRC decision and approved FERC transmission rate changes. The sales volume decrease was due to milder weather experienced during 2010 compared to the same period in 2009 and economic conditions. As a result of the CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk related to electricity sales (see "Overview of Ratemaking Mechanisms" in the 2009 Form 10-K).

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

Amounts 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 are remitted to the CDWR and are not recognized as revenue by SCE. The amounts collected and remitted to CDWR were $315 million and $896 million for the three- and nine-month periods ended September 30, 2010, respectively, and $493 million and $1.4 billion for the three- and nine-month periods ended September 30, 2009, respectively. Effective January 1, 2010, the CDWR-related rates were decreased to reflect lower power procurement expenses and to refund CDWR overcollections to customers.

Income Taxes

SCE's income tax expense from continuing operations decreased $31 million and increased $179 million during the three- and nine-month periods ended September 30, 2010, respectively. The 2010 income tax expense reflects: a $95 million earnings benefit relating to the California impact of the federal Global Settlement, including $53 million in the second quarter resulting from the acceptance by the Franchise Tax Board of the tax positions finalized with the IRS in 2009 and $42 million in the third quarter resulting from receipt of the final interest determination from the Franchise Tax Board; $39 million non-cash charge recorded in the first quarter related to the federal health care legislation enacted in March 2010; and a $40 million earnings benefit due to a change in method of tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program. During the nine months ended September 30, 2009, SCE recognized a $300 million earnings benefit related to the federal Global Settlement finalized with the IRS. See "SCE Notes to Consolidated Financial Statements Note 4. Income Taxes" for further discussion.

LIQUIDITY AND CAPITAL RESOURCES

SCE expects to fund its continuing obligations and projected capital investments for 2010 through cash and equivalents on hand, operating cash flows and incremental capital market financings of debt and preferred equity. 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 September 30, 2010, SCE had approximately $861 million of cash and equivalents and short-term investments. As of September 30, 2010, SCE's long-term debt, including current maturities of long-term debt, was $7.6 billion.

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The following table summarizes the status of SCE's credit facilities at September 30, 2010:

(in millions)	Credit Facilities1
Commitment	$	2,894
Outstanding borrowings		—
Outstanding letters of credit		(11	)
Amount available	$	2,883

¹

SCE has two revolving credit facilities with various banks; a $2.4 billion five-year credit facility that terminates in February 2013, with four one-year options to extend by mutual consent, and a $500 million three-year credit facility that terminates in March 2013.

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 September 30, 2010, SCE's debt to total capitalization ratio was 0.46 to 1.

Regulatory Proceedings

Energy Efficiency Risk/Reward Incentive Mechanism

As discussed in the year-ended 2009 MD&A, the CPUC adopted an Energy Efficiency Risk/Reward Incentive Mechanism applicable to the 2006 - 2008 performance period. In September 2010, the CPUC issued a proposed decision and an alternate proposed decision for the final payment. The proposed decision, if adopted, would result in no final payment, whereas, the alternate proposed decision, if adopted, would result in SCE receiving the previously projected $27 million final payment. SCE expects a CPUC decision on the final payment, if any, in late 2010. There is no assurance that SCE will receive a final payment.

2010 FERC Rate Case

In September 2009, the FERC issued an order allowing SCE to implement its proposed 2010 rates effective March 1, 2010, subject to refund. The proposed rates would increase SCE's FERC revenue requirement by $107 million, or 24%, over the 2009 FERC revenue requirement primarily due to an increase in transmission rate base, and would result in an approximate 1% increase to SCE's overall system average rate. SCE has terminated settlement negotiations and begun the litigation process for the proposed 2010 rates. A final decision is expected in the second half of 2011.

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 September 30, 2010, SCE's 13-month weighted-average common equity component of total capitalization was 51.1% resulting in the capacity to pay $502 million in additional dividends.

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SCE paid dividends to its parent, Edison International, of $100 million in both January 2010 and in September 2010. Future dividend amounts and timing of distributions are dependent upon several factors, including the actual level of capital investments, operating cash flows and earnings.

Income Tax Matters

In September 2010, President Obama signed the Small Business Jobs Act of 2010, which extended the 50% bonus depreciation provision for an additional year to include property purchased and placed into service by December 31, 2010. SCE expects that certain capital expenditures incurred during 2010 will qualify for the accelerated bonus depreciation, which would provide additional cash flow benefits in 2010, estimated to be in the range of approximately $250 million to $300 million.

Margin and Collateral Deposits

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. The table below illustrates the amount of collateral posted by SCE to its counterparties, as well as the potential collateral that would be required if SCE's credit rating fell below investment grade.

(in millions)	September 30, 2010
Collateral posted as of September 30, 20101	$	18
Incremental collateral requirements if SCE's credit rating was downgraded below investment grade		201
Total posted and potential collateral requirements2	$	219

¹

Collateral posted consisted of $5 million which was offset against net derivative liabilities and $13 million provided to counterparties and other brokers (consisting of $2 million in cash reflected in "Other current assets" on the consolidated balance sheets and $11 million in letters of credit).

²

Total posted and potential collateral requirements may increase by an additional $11 million, based on SCE's forward position as of September 30, 2010, due to adverse market price movements over the remaining life of the existing contracts using a 95% confidence level.

Historical Consolidated Cash Flows

This section discusses consolidated cash flows from operating, financing and investing activities.

Condensed Consolidated Statement of Cash Flows

	Nine Months Ended September 30,
(in millions)	2010			2009
Cash flows provided by operating activities	$	2,656		$	3,281
Cash flows provided (used) by financing activities		622			(1,854	)
Cash flows used by investing activities		(2,883	)		(2,284	)
Net increase (decrease) in cash and equivalents	$	395		$	(857	)

44

Cash Flows Provided by Operating Activities

Cash provided by operating activities decreased $625 million for the nine months ended 2010, compared to the same period in 2009 reflects lower net tax receipts in 2010 primarily resulting from the impacts of the Global Settlement. As a result of the Global Settlement, SCE received net tax allocation payments from Edison International of approximately $295 million and $875 million in 2010 and 2009, respectively. The 2010 change was also due to the timing of cash receipts and disbursements related to working capital items.

Cash Flows Provided (Used) by Financing Activities

Financing activities for the first nine months of 2010 were as follows:

•

Issued $1 billion of first refunding mortgage bonds due in 2040 to fund SCE's capital program.

•

Reissued $144 million of tax-exempt pollution control bonds due in 2035 to fund SCE's capital program.

•

Repaid $250 million of senior unsecured notes.

•

Paid $200 million in dividends to Edison International.

Financing activities for the first nine months of 2009 were as follows:

•

Issued $500 million of first refunding mortgage bonds due in 2039 and $250 million of first and refunding mortgage bonds due in 2014. The bond proceeds were used for general corporate purposes and to finance fuel inventories.

•

Repaid a net $1.9 billion of short-term debt.

•

Repaid $150 million of first and refunding mortgage bonds.

•

Purchased $219 million of two issues of tax-exempt pollution control bonds and converted the issues to a variable rate structure. As discussed above, SCE reissued $144 million of these bonds during the first nine months of 2010. SCE continues to hold the remaining $75 million of these bonds which are outstanding and have not been retired or cancelled.

•

Paid $200 million in dividends to Edison International.

Cash Flows Used by Investing Activities

Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Cash paid for capital expenditures was $2.7 billion and $2.1 billion for the nine months ended September 30, 2010 and 2009, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $133 million and $163 million for the nine months ended September 30, 2010 and 2009, respectively.

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Contractual Obligations and Contingencies

Contractual Obligations

SCE's long-term principal debt maturities plus interest payments as of September 30, 2010 are estimated to be: $102 million for the remainder of 2010, $408 million in 2011, $408 million in 2012, $408 million in 2013, $1.4 billion in 2014, and $13 billion for the period remaining thereafter. These amounts have been updated to reflect SCE's financing activities completed during 2010. For a discussion of issuances of long-term debt, see "SCE Notes to Consolidated Financial Statements Note 3. Liabilities and Lines of Credit—Long-Term Debt."

For a discussion of purchase obligations and capital lease obligations, see "SCE Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Lease Commitments and —Other Commitments."

Contingencies

Developments related to SCE's 2010 FERC Rate Case, FERC Transmission Incentives and CWIP Proceedings, Navajo Nation Litigation and Spent Nuclear Fuel are discussed in "SCE Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies."

Environmental Remediation

As of September 30, 2010, SCE identified 23 sites for remediation and recorded an estimated minimum liability of $38 million. SCE expects to recover 90% of its remediation costs at certain sites. SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $3 million to $18 million. See "SCE Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies" for further discussion.

MARKET RISK EXPOSURES

For a detailed discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Market Risk Exposures—Commodity Price Risk" in the year-ended 2009 MD&A.

Interest Rate Risk

At September 30, 2010, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $8.7 billion, compared to a carrying value of $7.6 billion. At September 30, 2010, SCE did not believe that its short-term debt was subject to interest rate risk due to the fair value being approximately equal to the carrying value.

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Commodity Price Risk

Natural Gas and Electricity Price Risk

The following table summarizes the fair values of outstanding derivative instruments used at SCE to mitigate its exposure to spot market prices. For further discussion on fair value measurements, see "SCE Notes to Consolidated Financial Statements Note 9. Fair Value Measurements."

	September 30, 2010					December 31, 2009
(in millions)	Assets		Liabilities			Assets		Liabilities
Electricity options, swaps and forward arrangements	$	3	$	75		$	1	$	25
Natural gas options, swaps and forward arrangements		81		338			86		171
Congestion revenue rights		177		—			217		—
Tolling arrangements1		—		1,115			43		402
Netting and collateral		—		(5	)		—		—
Total	$	261	$	1,523		$	347	$	598

¹

In compliance with a CPUC mandate, SCE held an open, competitive solicitation that produced agreements with different project developers who have agreed to construct new southern California generating resources. The contracts provide for fixed capacity payments as well as pricing for energy delivered based on a heat rate and contractual operation and maintenance prices. However, due to uncertainty regarding the availability of required emission credits, some of the generating resources may not be constructed and the contracts associated with these resources could therefore terminate, at which time SCE would no longer account for these contracts as derivatives.

The change in the fair value of derivative contracts for the nine months ended September 30, 2010 was as follows:

(in millions)
Fair value of derivative contracts, net liability at January 1, 2010		$	(251	)
Total realized/unrealized net losses:
	Included in regulatory assets and liabilities1		(1,138	)
Purchases and settlements, net			122
Netting and collateral			5
Fair value of derivative contracts, net liability at September 30, 2010		$	(1,262	)

¹

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

SCE recognizes realized gains and losses on derivative instruments as purchased power expense and recovers these costs, subject to reasonableness review, 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 or liabilities and therefore are not reflected in earnings. Realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than contract prices. Unrealized losses on economic hedging activities were primarily due to the declining gas and power prices related to SCE's new generation contracts and the decreasing forward natural gas prices related to financial natural gas contracts.

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Credit Risk

Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. As of September 30, 2010, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:

	September 30, 2010
(in millions)	Exposure2		Collateral		Net Exposure
S&P Credit Rating1
A or higher	$	187	$	—	$	187
A-		—		—		—
BBB+		—		—		—
BBB		—		—		—
BBB-		—		—		—
Below investment grade and not rated		—		—		—
Total	$	187	$	—	$	187

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.

The credit risk exposure set forth in the above table is composed of less than $1 million of net account receivables and $187 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

The CAISO comprises 94% of the total net exposure above and is mainly related to the CRRs' fair value (see "—Commodity Price Risk" for further information).

NEW ACCOUNTING GUIDANCE

New accounting guidance is discussed in "SCE Notes to Consolidated Financial Statements Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4T. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SCE's management, under the supervision and with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of SCE's disclosure controls and

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

Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Navajo Nation Litigation

Developments related to the Navajo Nation litigation are discussed in "SCE Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Navajo Nation Litigation."

California Coastal Commission Potential Environmental Proceeding

In May 2010, the California Coastal Commission issued a NOV to SCE, its contractor, and property owners related to activity on a property that was used for equipment storage related to a nearby SCE electricity line undergrounding construction project. The NOV alleged that SCE, through its contractor, violated the California Coastal Act by removing without the appropriate permits approximately one acre of vegetation from the property, which was located in a protected coastal zone within and adjacent to the City of Newport Beach, California. In the NOV, the Coastal Commission indicated an interest in negotiating a settlement of the alleged violations but no specific settlement terms have been proposed nor has a settlement been reached. The Coastal Act provides for penalties of up to $30,000 per violation, which may be increased by up to $15,000 per day per violation for knowing and intentional violations. SCE has sought indemnification from its contractor for liability associated with the NOV.

ITEM 6. EXHIBITS

31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32	Statement Pursuant to 18 U.S.C. Section 1350
101	Financial statements from the quarterly report on Form 10-Q of Edison International for the quarter ended September 30, 2010, filed on October 29, 2010, 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

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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: October 29, 2010

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