SOUTHERN CALIFORNIA EDISON (SCE-PN) 10-Q 2010 Q2 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 June 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 filero Accelerated filero Non-accelerated filerý
(Do not check if a smaller
reporting company) Smaller reporting companyo

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

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

Class	Outstanding at August 2, 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
		Greenhouse Gas Regulation Developments		36
		California Renewable Energy Developments		36
		Once-Through Cooling		36
	RESULTS OF OPERATIONS			37
	Electric Utility Results of Operations			38
		Three Months Ended June 30, 2010 versus June 30, 2009		38
			Utility Earning Activities	39
			Utility Cost-Recovery Activities	40

		Six Months Ended June 30, 2010 versus June 30, 2009		41
			Utility Earning Activities	41
			Utility Cost-Recovery Activities	43
		Supplemental Operating Revenue Information		43
		Income Taxes		44
	LIQUIDITY AND CAPITAL RESOURCES			44
	Available Liquidity			44
		Debt Covenant		44
	Regulatory Proceedings			45
		Energy Efficiency Risk/Reward Incentive Mechanism		45
		2010 FERC Rate Case		45
	Dividend Restrictions			45
	Margin and Collateral Deposits			45
	Historical Consolidated Cash Flow			46
		Condensed Consolidated Statement of Cash Flows		46
			Cash Flows Provided by Operating Activities	46
			Cash Flows Provided (Used) by Financing Activities	46
			Cash Flows Used by Investing Activities	47
	Contractual Obligations and Contingencies			47
		Contractual Obligations		47
		Contingencies		47
			Environmental Remediation	47
	MARKET RISK EXPOSURES			47
	Interest Rate Risk			47
	Commodity Price Risk			48
		Natural Gas and Electricity Price Risk		48
	Credit Risk			49
	NEW ACCOUNTING GUIDANCE			50
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				50
ITEM 4T. CONTROLS AND PROCEDURES				50
	Disclosure Controls and Procedures			50
	Internal Control Over Financial Reporting			50
PART II. OTHER INFORMATION				50
ITEM 1. LEGAL PROCEEDINGS				50
	Navajo Nation Litigation			50
ITEM 6. EXHIBITS				51
SIGNATURE				52

GLOSSARY

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

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.
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

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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
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 June 30,						Six Months Ended June 30,
(in millions)	2010			2009			2010			2009
	(Unaudited)
Operating revenue	$	2,247		$	2,273		$	4,406		$	4,462
Fuel		94			156			175			356
Purchased power		612			583			1,220			1,124
Operation and maintenance		755			762			1,468			1,420
Depreciation, decommissioning and amortization		320			289			629			574
Property and other taxes		62			61			130			127
Gain on sale of assets		—			(1	)		—			(1	)
Total operating expenses		1,843			1,850			3,622			3,600
Operating income		404			423			784			862
Interest income		2			2			3			6
Other income		35			29			70			56
Interest expense – net of amounts capitalized		(107	)		(106	)		(206	)		(215	)
Other expenses		(15	)		(12	)		(26	)		(20	)
Income before income taxes		319			336			625			689
Income tax expense (benefit)		5			(198	)		134			(77	)
Net income		314			534			491			766
Less: Net income attributable to noncontrolling interests		—			22			—			34
Dividends on preferred and preference stock not subject to mandatory redemption		13			13			26			25
Net income available for common stock	$	301		$	499		$	465		$	707

Consolidated Statements of Comprehensive Income
			Three Months Ended June 30,				Six Months Ended June 30,
(in millions)			2010		2009		2010		2009
			(Unaudited)
Net income			$	314	$	534	$	491	$	766
Other comprehensive income, net of tax:
	Pension and postretirement benefits other than pensions:
		Amortization of net loss included in net income		1		1		2		1
Comprehensive income				315		535		493		767
Less: Comprehensive income attributable to noncontrolling interests				—		22		—		34
Comprehensive income attributable to SCE			$	315	$	513	$	493	$	733

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)			June 30, 2010			December 31, 2009
			(Unaudited)
ASSETS
Cash and equivalents			$	85		$	462
Short-term investments				6			9
Receivables, less allowances of $53 for uncollectible accounts at both dates				731			719
Accrued unbilled revenue				542			347
Inventory				323			337
Prepaid taxes				200			33
Derivative assets				78			160
Regulatory assets				338			120
Deferred income taxes				—			78
Other current assets				51			64
Total current assets				2,354			2,329
Nonutility property – less accumulated depreciation of $95 and $744 at respective dates				68			324
Nuclear decommissioning trusts				3,083			3,140
Other investments				82			67
Total investments and other assets				3,233			3,531
Utility plant, at original cost:
	Transmission and distribution			23,355			22,214
	Generation			2,715			2,667
Accumulated depreciation				(6,047	)		(5,921	)
Construction work in progress				2,682			2,701
Nuclear fuel, at amortized cost				339			305
Total utility plant				23,044			21,966
Derivative assets				197			187
Regulatory assets				5,058			4,139
Other long-term assets				327			322
Total long-term assets				5,582			4,648
Total assets			$	34,213		$	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)		June 30, 2010			December 31, 2009
		(Unaudited)
LIABILITIES AND EQUITY
Short-term debt		$	215		$	—
Current portion of long-term debt			—			250
Accounts payable			971			1,282
Accrued taxes			31			9
Accrued interest			180			162
Customer deposits			229			238
Derivative liabilities			179			102
Regulatory liabilities			457			367
Deferred income taxes			52			—
Other current liabilities			445			637
Total current liabilities			2,759			3,047
Long-term debt			7,129			6,490
Deferred income taxes			3,959			3,651
Deferred investment tax credits			94			97
Customer advances			124			119
Derivative liabilities			1,188			496
Pensions and benefits			1,725			1,681
Asset retirement obligations			3,278			3,198
Regulatory liabilities			3,391			3,328
Other deferred credits and other long-term liabilities			1,730			1,652
Total deferred credits and other liabilities			15,489			14,222
Total liabilities			25,377			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			561			551
Accumulated other comprehensive loss			(17	)		(19	)
Retained earnings			5,204			4,746
Total common shareholder's equity			7,916			7,446
Preferred and preference stock not subject to mandatory redemption			920			920
Noncontrolling interests			—			349
Total equity			8,836			8,715
Total liabilities and equity		$	34,213		$	32,474

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

3

Consolidated Statements of Cash Flows		Southern California Edison Company
			Six Months Ended June 30,
(in millions)			2010			2009
			(Unaudited)
Cash flows from operating activities:
Net income			$	491		$	766
Adjustments to reconcile to net cash provided by operating activities:
	Depreciation, decommissioning and amortization			629			574
	Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)			74			86
	Other amortization			50			55
	Stock-based compensation			8			6
	Deferred income taxes and investment tax credits			221			447
Changes in operating assets and liabilities:
	Receivables			(41	)		15
	Inventory			(2	)		40
	Margin and collateral deposits – net of collateral received			—			(16	)
	Prepaid taxes			(167	)		178
	Other current assets			(189	)		(181	)
	Accounts payable			(104	)		(64	)
	Accrued taxes			22			(277	)
	Other current liabilities			(75	)		(50	)
	Derivative assets and liabilities – net			841			(626	)
	Regulatory assets and liabilities – net			(720	)		761
	Other assets			(18	)		(106	)
	Other liabilities			75			446
Net cash provided by operating activities				1,095			2,054
Cash flows from financing activities:
Long-term debt issued				644			750
Long-term debt issuance costs				(15	)		(11	)
Long-term debt repaid				(253	)		(151	)
Bonds repurchased				—			(219	)
Short-term debt financing – net				215			(1,893	)
Settlements of stock-based compensation – net				(1	)		—
Distributions to noncontrolling interest				—			(45	)
Dividends paid				(125	)		(125	)
Net cash provided (used) by financing activities				465			(1,694	)
Cash flows from investing activities:
Capital expenditures				(1,757	)		(1,402	)
Proceeds from sale of nuclear decommissioning trust investments				600			1,310
Purchases of nuclear decommissioning trust investments and other				(697	)		(1,415	)
Sales of short-term investments				4			1
Purchases of short-term investments				(1	)		(1	)
Customer advances for construction and other investments				6			(10	)
Effect of deconsolidation of variable interest entities				(92	)		—
Net cash used by investing activities				(1,937	)		(1,517	)
Net decrease in cash and equivalents				(377	)		(1,157	)
Cash and equivalents, beginning of period				462			1,611
Cash and equivalents, end of period			$	85		$	454

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 six-month periods ended June 30, 2010 are not necessarily indicative of the operating results for the full year.

Management has performed an evaluation of subsequent events through the date the financial statements were issued.

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 $54 million and $360 million at June 30, 2010 and December 31, 2009, respectively. The carrying value of cash equivalents equals 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 $201 million and $224 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at June 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 presents margin and cash collateral deposits subject to a master netting arrangement netted with its

5

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

(in millions)		June 30, 2010		December 31, 2009
		(Unaudited)
Collateral provided to counterparties:
	Offset against derivative liabilities	$	8	$	—
	Reflected in other current assets		4		6
Collateral received from counterparties:
	Reflected in other current liabilities		57		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

Accounting pronouncements recently issued by the FASB (including its Emerging Issues Task Force), the American Institute of Certified Public Accountants and the SEC that are effective after June 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 Mountainview and peaker plants, bilateral contracts where pricing is based on natural gas prices (this includes contract energy prices for most 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	June 30, 2010		December 31, 2009
		(Unaudited)
Electricity options, swaps and forward arrangements	GWh		14,686		14,868
Natural gas options, swaps and forward arrangements	Bcf		278		266
Congestion revenue rights	GWh		165,097		195,367
Tolling arrangements1	GWh		116,398		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 June 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	$	78	$	197	$	275	$	187	$	1,188	$	1,375	$	1,100
Netting and collateral		—		—		—		8		—		8		8
Total	$	78	$	197	$	275	$	179	$	1,188	$	1,367	$	1,092

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, 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. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.

The following table summarizes the components of economic hedging activity:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2010			2009			2010			2009
	(Unaudited)
Realized gain (loss)	$	(38	)	$	(96	)	$	(62	)	$	(194	)
Unrealized gain (loss)		(276	)		293			(857	)		626

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

8

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 $232 million and $91 million, as of June 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 June 30, 2010, SCE would be required to post $20 million of additional collateral.

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. The proceeds from these bonds were used to repay commercial paper borrowings and for general corporate purposes.

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.

Short-term debt is generally used to finance fuel inventories, balancing account under-collections and general, temporary cash requirements including power purchase payments. At June 30, 2010, the outstanding short-term debt was $215 million at a weighted-average interest rate of 0.42%. This short-term debt is supported by $2.9 billion of credit lines. At December 31, 2009, the outstanding short-term debt was zero.

At June 30, 2010, letters of credit issued under SCE's credit facilities aggregated $11 million and were scheduled to expire in 2010.

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Note 4. Income Taxes

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 June 30,						Six Months Ended June 30,
(in millions)		2010			2009			2010			2009
		(Unaudited)
Provision for income tax at federal statutory rate of 35%		$	112		$	110		$	219		$	229
Increase (decrease) in income tax from:
Items presented with related state income tax, net
	Global settlement related		(53	)		(300	)		(53	)		(300	)
	Change in tax accounting method for asset removal costs		(40	)		—			(40	)		—
State tax – net of federal benefit			19			23			21			27
Health care legislation			—			—			39			—
Property-related and other			(33	)		(31	)		(52	)		(33	)
Total income tax expense from continuing operations		$	5		$	(198	)	$	134		$	(77	)
Pre-tax income from continuing operations		$	319		$	314		$	624		$	655
Effective tax rate			2%			(63%	)		21%			(12%	)

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 the second quarter of 2010, SCE recognized a $53 million earnings benefit resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002 (described in "Item 8. SCE Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K). Edison International is awaiting receipt of final interest calculations from the California Franchise Tax Board. During the second quarter of 2009, SCE recognized a $300 million earnings benefit related to the federal Global Settlement finalized with the IRS.

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.

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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. 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, Edison International 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 June 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		31			28
Tax positions taken during a prior year:
Increases		133			138
Decreases		(42	)		(25	)
Decreases for settlements during the period		(68	)		(1,741	)
Balance at June 30	$	536		$	466

As of June 30, 2010 and December 31, 2009, respectively, if recognized, $160 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 $71 million and $79 million as of June 30, 2010 and December 31, 2009, respectively.

The after-tax interest income recognized and included in income tax expense was $24 million and $292 million for the three months ended June 30, 2010 and 2009, respectively, and was $22 million and $289 million for the six months ended June 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 six months ended June 30, 2010, SCE made 2010 plan year contributions of $51 million and expects to make $30 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 June 30,						Six Months Ended June 30,
(in millions)	2010			2009			2010			2009
	(Unaudited)
Service cost	$	29		$	27		$	58		$	54
Interest cost		49			48			98			96
Expected return on plan assets		(49	)		(40	)		(98	)		(80	)
Amortization of prior service cost		2			4			4			8
Amortization of net loss		6			13			12			26
Expense under accounting standards	$	37		$	52		$	74		$	104
Regulatory adjustment – deferred		(14	)		(37	)		(28	)		(74	)
Total expense recognized	$	23		$	15		$	46		$	30

Postretirement Benefits Other Than Pensions

During the six months ended June 30, 2010, SCE made 2010 plan year contributions of $14 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 June 30,						Six Months Ended June 30,
(in millions)	2010			2009			2010			2009
	(Unaudited)
Service cost	$	7		$	10		$	14		$	20
Interest cost		30			34			60			68
Expected return on plan assets		(25	)		(21	)		(50	)		(42	)
Amortization of prior service cost (credit)		(9	)		(7	)		(18	)		(14	)
Amortization of net loss		8			15			16			30
Total expense	$	11		$	31		$	22		$	62

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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 "Other operation and maintenance" on the consolidated statements of income) was $5 million and $6 million for the three months ended June 30, 2010 and 2009, respectively, and $10 million and $9 million for the six months ended June 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 June 30, 2010 and 2009, and $4 million for both the six months ended June 30, 2010 and 2009. Consistent with SCE's 2009 GRC, no stock-based compensation has been capitalized since December 31, 2008. Excess tax benefits included in "Settlements of stock-based compensation – net" in the financing section of the consolidated statements of cash flows were $2 million for both the six months ended June 30, 2010 and 2009.

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		2,082,894			33.24
Forfeited		(57,796	)		31.92
Exercised		(216,174	)		22.46
Affiliate transfers – net		28,554			36.33
Outstanding at June 30, 2010		10,586,493			32.38		6.76
Vested and expected to vest at June 30, 2010		10,301,100			32.38		6.70	$	40,387,444
Exercisable at June 30, 2010		5,764,144			32.52		5.09		27,650,336

SCE's cash outflows to purchase Edison International shares in the open market to settle stock options exercised were $4 million and $1 million for the three months ended June 30, 2010 and 2009, respectively, and $7 million and $5 million for the six months ended June 30, 2010 and 2009, respectively. Cash inflows from participants to exercise stock options were $2 million and $1 million for the three months ended June 30, 2010 and 2009, respectively, and $5 million and $3 million for the six months ended June 30, 2010 and 2009, respectively. The tax benefit realized from options exercised was less than $1 million for both the three months ended June 30, 2010 and 2009, and $1 million for both the six months ended June 30, 2010 and 2009.

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Performance Shares

The following is a summary of the status of Edison International nonvested performance shares granted to SCE employees and classified as equity awards:

	Performance Shares			Weighted-Average Grant Date Fair Value
	(Unaudited)
Nonvested at December 31, 2009		172,604		$	36.65
Granted		78,765			32.31
Forfeited		(34,180	)		56.24
Affiliate transfers – net		791			41.62
Nonvested at June 30, 2010		217,980			32.19

The following is a summary of the status of Edison International nonvested performance shares granted to SCE employees and classified as liability awards (the current portion is reflected in the caption "Other current liabilities" and the long-term portion is reflected in "Accumulated provision for pensions and benefits" on the consolidated balance sheets):

	Performance Shares			Weighted-Average Fair Value
	(Unaudited)
Nonvested at December 31, 2009		172,604
Granted		78,765
Forfeited		(34,180	)
Affiliate transfers – net		791
Nonvested at June 30, 2010		217,980		$	20.37

There were no performance shares settled in 2009 or 2010.

Note 6. Commitments and Contingencies

Commitments

SCE entered into a 20-year power purchase contract which is classified as a capital lease and is expected to be recorded on the consolidated balance sheets upon commencement of the contract in 2013. SCE's commitments upon commencement are estimated to be: $23 million in 2013, $44 million in 2014, and $805 million for the period remaining thereafter.

Other Commitments

At June 30, 2010, SCE had power purchase contracts with additional commitments estimated to be: $67 million for the remainder of 2010, $83 million in 2011, $67 million in 2012, $39 million in 2013, $39 million in 2014, and $613 million for the period remaining thereafter.

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

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Indemnities

Indemnity Provided as Part of the Acquisition of Mountainview

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific environmental claims related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilities with respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.

Mountainview Filter Cake Indemnity

The Mountainview power plant utilizes water from on-site groundwater wells and City of Redlands ("City") recycled water for cooling purposes. Unrelated to the operation of the plant, this water 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. SCE believes that the outcome of these other proceedings will not materially affect its results of operations or liquidity.

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

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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.

California Renewable Energy Developments

In June 2010, CARB released a proposed 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 California legislature is also contemplating legislation to adopt a 33% renewables portfolio standard that may supersede the CARB regulation and impose its own program structure. Due to the possibility of legislation, the CARB has postponed voting on its proposed regulation until September 2010 at the Governor's request. 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 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

Petitions for judicial review of the greenhouse gas tailoring rule are to be submitted by August 2, 2010. Legal challenges to the greenhouse gas tailoring rule have been filed.

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 conducted 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. It 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.

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Environmental Remediation

SCE records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, SCE records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts.

As of June 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 $223 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 $32 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 June 30, 2010 and 2009, respectively, and $3 million and $5 million for the six months ended June 30, 2010 and 2009, respectively.

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

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Federal and State Income Taxes

Edison International's 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 California state income tax returns are subject to examination for tax years 1991 through 2009.

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: 125 basis point adder for both DPV2 and Tehachapi, and a 75 basis point adder for Rancho Vista. The CPUC filed an appeal of this 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 June 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 outcomes of the 2009 and 2010 CWIP proceedings are still pending. SCE began collecting the 2010 CWIP revenue requirements in rates on June 1, 2010. 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. 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. No trial date has been set for this litigation. SCE cannot predict the outcome of the Tribes' complaints 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

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insurance at that plant site, all nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.

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

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $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, 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. Additional legal action would be necessary to recover damages incurred after that date. The decision is subject to appeal by the DOE. 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 six months ended June 30, 2010.

	Equity Attributable to SCE
(in millions)	Common Stock		Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Preferred and Preference Stock		Noncontrolling Interest			Total Equity
	(Unaudited)
Balance at December 31, 2009	$	2,168	$	551	$	(19	)	$	4,746		$	920	$	349		$	8,715
Net income		—		—					491			—		—			491
Other comprehensive income		—		—		2			—			—		—			2
Deconsolidation of variable interest entities (see Note 12)		—		—		—			—			—		(349	)		(349	)
Dividends declared on preferred and preference stock not subject to mandatory redemption		—		—		—			(26	)		—		—			(26	)
Stock-based compensation – net		—		2		—			(3	)		—		—			(1	)
Noncash stock-based compensation and other		—		8		—			(4	)		—		—			4
Balance at June 30, 2010	$	2,168	$	561	$	(17	)	$	5,204		$	920	$	—		$	8,836

The following table provides changes in equity for the six months ended June 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		—		—		—			732			—		34			766
Other comprehensive income		—		—		1			—			—		—			1
Distributions to noncontrolling interests		—		—		—			—			—		(45	)		(45	)
Dividends declared on common stock		—		—		—			(100	)		—		—			(100	)
Dividends declared on preferred and preference stock not subject to mandatory redemption		—		—		—			(25	)		—		—			(25	)
Stock-based compensation – net		—		2		—			(2	)		—		—			—
Noncash stock based compensation and other		—		6		—			(2	)		—		—			4
Balance at June 30, 2009	$	2,168	$	540	$	(13	)	$	4,430		$	920	$	369		$	8,414

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Note 8. Supplemental Cash Flows Information

The following is SCE's supplemental cash flows information:

		Six Months Ended June 30,
(in millions)		2010			2009
		(Unaudited)
Cash payments (receipts) for interest and taxes
	Interest – net of amounts capitalized	$	162		$	170
	Tax receipts		(12	)		(868	)
Noncash investing and financing activities
	Details of debt exchange:
	Pollution-control bonds redeemed	$	(203	)	$	—
	Pollution-control bonds issued		203			—
	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		13			13

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 (from one or more brokers) 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.

In assessing nonperformance risks, SCE reviews credit ratings of counterparties (and related default rates based on such credit ratings). The fair value of derivative assets and derivative liabilities nonperformance risks was $1 million and $9 million, respectively at June 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 June 30, 2010
(in millions)			Level 1		Level 2			Level 3			Netting and Collateral1		Total
			(Unaudited)
Assets at Fair Value
	Money market funds2		$	54	$	—		$	—		$	—	$	54
	Derivative contracts:
		Electricity		—		—			1			—		1
		Natural Gas		—		1			83			—		84
		CRRs		—		—			190			—		190
		Subtotal of derivative contracts		—		1			274			—		275
	Long-term disability plan			9		—			—			—		9
	Nuclear decommissioning trusts:
		Stocks3		1,635		—			—			—		1,635
		Municipal bonds		—		703			—			—		703
		Corporate bonds4		—		395			—			—		395
		U.S. government and agency securities		262		54			—			—		316
		Short-term investments, primarily cash equivalents5		—		12			—			—		12
		Subtotal of nuclear decommissioning trusts		1,897		1,164			—			—		3,061
Total assets6			$	1,960	$	1,165		$	274		$	—	$	3,399
Liabilities at Fair Value
	Derivative contracts:
		Electricity	$	—	$	—		$	(89	)	$	1	$	(88	)
		Natural Gas		—		(232	)		(48	)		7		(273	)
		Tolling		—		—			(1,006	)		—		(1,006	)
		Subtotal of derivative contracts		—		(232	)		(1,143	)		8		(1,367	)
Net assets (liabilities)			$	1,960	$	933		$	(869	)	$	8	$	2,032

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 June 30, 2010 and December 31, 2009, approximately 68% and 67% of the equity investments were located in the United States, respectively.

⁴

Corporate bonds are diversified. At June 30, 2010 and December 31, 2009, this category included $37 million and $50 million, respectively, for collateralized mortgage obligations and other asset backed securities.

⁵

Excludes net assets of $22 million and $18 million of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases at June 30, 2010 and December 31, 2009, respectively.

⁶

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

24

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

		Three Months Ended June 30,						Six Months Ended June 30,
(in millions)		2010			2009			2010			2009
		(Unaudited)
Fair value of derivative contracts, net liability at beginning of period		$	(596	)	$	(126	)	$	(111	)	$	(518	)
Total realized/unrealized gains (losses):
	Included in earnings		—			—			—			—
	Included in regulatory assets and liabilities1		(294	)		204			(781	)		591
Purchases and settlements, net			21			39			23			44
Transfers into Level 3			—			—			—			—
Transfers out of Level 3			—			—			—			—
Fair value, net asset (liability) at end of period		$	(869	)	$	117		$	(869	)	$	117
Change during the period in unrealized gains (losses) related to assets and liabilities held at the end of period		$	(285	)	$	212		$	(749	)`	$	604

¹

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

There were no transfers between levels during the first six months of 2010. SCE determines the fair value for transfers in and transfers out of each level as of the end of each reporting period.

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 $46 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		June 30, 2010		December 31, 2009		June 30, 2010		December 31, 2009
			(Unaudited)
Stocks		–	$	843	$	822	$	1,635	$	1,772
Municipal bonds		2010 – 2047		602		545		703		634
Corporate bonds		2010 – 2044		317		309		395		393
U.S. government and agency securities		2010 – 2039		285		287		316		308
Short-term investments and receivables/payables		2010		33		33		34		33
Total			$	2,080	$	1,996	$	3,083	$	3,140

¹

Maturity dates as of June 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 $315 million and

25

$652 million for the three months ended June 30, 2010 and 2009, respectively and $600 million and $1.3 billion for the six months ended June 30, 2010 and 2009, respectively. Unrealized holding gains, net of losses, were $1.0 billion and $1.1 billion at June 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 June 30,						Six Months Ended June 30,
(in millions)	2010			2009			2010			2009
	(Unaudited)
Balance at beginning of period	$	3,248		$	2,399		$	3,140		$	2,524
Realized gains		18			115			38			189
Realized losses		(5	)		(77	)		(4	)		(140	)
Unrealized gains (losses) – net		(205	)		220			(143	)		148
Other-than-temporary impairment		(7	)		(9	)		(11	)		(103	)
Interest, dividends, contributions and other		34			25			63			55
Balance at end of period	$	3,083		$	2,673		$	3,083		$	2,673

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:

	June 30, 2010				December 31, 2009
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Unaudited)
Long-term debt, including current portion	$	7,129	$	8,056	$	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)	June 30, 2010		December 31, 2009
	(Unaudited)
Current:
Regulatory balancing accounts	$	194	$	94
Energy derivatives		143		25
Other		1		1
		338		120
Long-term:
Regulatory balancing accounts		43		43
Deferred income taxes – net		1,775		1,561
Unamortized nuclear investment – net		310		340
Nuclear-related ARO investment – net		248		258
Unamortized coal plant investment – net		71		73
Unamortized loss on reacquired debt		277		287
Pensions and other postretirement benefits		1,004		1,014
Energy derivatives		1,092		357
Environmental remediation		39		36
Other		199		170
		5,058		4,139
Total regulatory assets	$	5,396	$	4,259

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	June 30, 2010		December 31, 2009
	(Unaudited)
Current:
Regulatory balancing accounts	$	455	$	363
Other		2		4
		457		367
Long-term:
Regulatory balancing accounts		808		642
ARO		12		171
Costs of removal		2,571		2,515
		3,391		3,328
Total regulatory liabilities	$	3,848	$	3,695

27

Note 11. Other Income and Expenses

Other income and expenses are as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2010		2009		2010		2009
	(Unaudited)
Other Income:
Equity AFUDC	$	25	$	18	$	54	$	35
Increase in cash surrender value of life insurance policies		6		6		12		13
Other		4		5		4		8
Total other income	$	35	$	29	$	70	$	56
Other Expenses:
Civic, political and related activities and donations	$	9	$	6	$	15	$	8
Marketing services		2		6		3		6
Other		4		—		8		6
Total other expenses	$	15	$	12	$	26	$	20

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 does not control the commercial and operating activities of these entities. In general, because payments

28

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 1,749 MW at June 30, 2010 and the amounts that SCE paid to these projects were $117 million and $115 million for the three months ended June 30, 2010 and 2009, respectively, and $242 million and $231 million for the six months ended June 30, 2010 and 2009, respectively. These amounts are recoverable in customer rates.

The following table summarizes as of June 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	$	—	$	—	$	42	$	964	$	—
Accounts payable		—		—		59		—		—
Total	$	—	$	—	$	101	$	964	$	—

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, 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, consolidated these projects. SCE prospectively deconsolidated the Big 4 Projects at January 1, 2010

29

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

30

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

	Three Months Ended June 30, 2009
(in millions)	Electric Utility			VIEs		Eliminations			SCE
	(Unaudited)
Operating revenue	$	2,227		$	131	$	(85	)	$	2,273
Fuel		80			76		—			156
Purchased power		668			—		(85	)		583
Operation and maintenance		737			25		—			762
Depreciation, decommissioning and amortization		281			8		—			289
Property and other taxes		61			—		—			61
Gain on sale of assets		(1	)		—		—			(1	)
Total operating expenses		1,826			109		(85	)		1,850
Operating income		401			22		—			423
Interest income		2			—		—			2
Other income		29			—		—			29
Interest expense – net of amounts capitalized		(106	)		—		—			(106	)
Other expenses		(12	)		—		—			(12	)
Income tax benefit		198			—		—			198
Net income		512			22		—			534
Less: Net income attributable to noncontrolling interest		—			22		—			22
Dividends on preferred and preference stock not subject to mandatory redemption		13			—		—			13
Net income available for common stock	$	499		$	—	$	—		$	499

	Six Months Ended June 30, 2009
(in millions)	Electric Utility			VIEs		Eliminations			SCE
	(Unaudited)
Operating revenue	$	4,356		$	274	$	(168	)	$	4,462
Fuel		179			177		—			356
Purchased power		1,292			—		(168	)		1,124
Operation and maintenance		1,374			46		—			1,420
Depreciation, decommissioning and amortization		557			17		—			574
Property and other taxes		127			—		—			127
Gain on sale of assets		(1	)		—		—			(1	)
Total operating expenses		3,528			240		(168	)		3,600
Operating income		828			34		—			862
Interest income		6			—		—			6
Other income		56			—		—			56
Interest expense – net of amounts capitalized		(215	)		—		—			(215	)
Other expenses		(20	)		—		—			(20	)
Income tax benefit		77			—		—			77
Net income		732			34		—			766
Less: Net income attributable to noncontrolling interest		—			34		—			34
Dividends on preferred and preference stock not subject to mandatory redemption		25			—		��			25
Net income available for common stock	$	707		$	—	$	—		$	707

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, natural disasters and other unforeseen events;

•

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 six-month periods ended June 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 six-month periods ended June 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 June 30,							Six Months Ended June 30,
(in millions)		2010		2009		Change			2010			2009		Change
Net income available for common stock		$	301	$	499	$	(198	)	$	465		$	707	$	(242	)
Non-Core Earnings (Loss)
	Global Settlement		53		300		(247	)		53			300		(247	)
	Tax impact of health care legislation		—		—		—			(39	)		—		(39	)
Core Earnings		$	248	$	199	$	49		$	451		$	407	$	44

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 our earnings results to facilitate comparisons of the Company's 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, change in tax law and nonrecurring regulatory or legal proceedings.

SCE's 2010 core earnings increased $49 million and $44 million for the quarter and year-to-date, respectively. The quarter increase was due to lower income tax expense and higher authorized revenue to support rate base growth. These quarter increases were partially offset by higher operating expenses, including the impact of curtailed spending last year due to the timing of the 2009 CPUC GRC decision. 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). These year-to-date increases were partially offset by higher operating expenses, including the impact of curtailed spending last year due to the timing of the 2009 CPUC GRC decision. The lower tax expense for the quarter and year-to-date 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 $53 million recorded in the second quarter of 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002 (described in "Item 8. SCE Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K). Edison International is awaiting receipt of final interest calculations from the California Franchise Tax Board.

•

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. 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.

•

After-tax earnings of $300 million recorded in the second quarter of 2009, which resulted from the Global Settlement with the IRS.

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 returned to service on April 11, 2010. 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 referred to as EdisonSmartConnect™. During the first six months of 2010, SCE installed approximately 860,000 smart meters, with cumulative installations totaling over 1 million.

SCE continues to plan to utilize cash generated from its operations and issuance of additional debt and preferred equity for its capital program. During the six months ended June 30, 2010, SCE issued long-term debt (see "Liquidity and Capital Resources—Historical Consolidated Cash Flow—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 six months ended June 30, 2010 totaled $1.5 billion. SCE projects that capital investments will be in the range of $3.3 billion to $4.0 billion in 2010 and the 2010 – 2014 total capital investment spending will be in the range of $18 billion to $21.5 billion. 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 Plans" 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

Greenhouse Gas Regulation Developments

In June 2010, the US EPA published its final greenhouse gas tailoring rule, with less stringent statutory emissions thresholds for greenhouse gases than those originally proposed in late 2009. Since the rule affects only new or modified sources, it is not expected to have any immediate effect, on the existing fossil-fuel generating stations of SCE.

California Renewable Energy Developments

In June 2010, CARB released a proposed 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 California legislature is also contemplating legislation to adopt a 33% renewables portfolio standard that may supersede the CARB regulation and impose its own program structure. 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.

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 conducted regarding the feasibility of compliance by California's two coastal nuclear power plants. Depending on the results of the study, the

36

required compliance may result in significant capital expenditures at San Onofre and may affect its operations. It 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.

For further discussion, 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.

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.

37

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 June 30, 2010 versus June 30, 2009

		Three Months Ended June 30, 2010								Three Months Ended June 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		$	1,308		$	939	$	2,247		$	1, 253		$	1,020		$	2,273
Fuel and purchased power			—			706		706			—			739			739
Operation and maintenance			537			218		755			516			246			762
Depreciation, decommissioning and amortization			306			14		320			275			14			289
Property and other taxes			61			1		62			61			—			61
Gain on sale of assets			—			—		—			—			(1	)		(1	)
Total operating expenses			904			939		1,843			852			998			1,850
Operating income			404			—		404			401			22			423
Net interest expense and other			(85	)		—		(85	)		(87	)		—			(87	)
Income before income taxes			319			—		319			314			22			336
Income tax expense (benefit)			5			—		5			(198	)		—			(198	)
Net income			314			—		314			512			22			534
Net income attributable to noncontrolling interests			—			—		—			—			22			22
Dividends on preferred and preference stock not subject to mandatory redemption			13			—		13			13			—			13
Net income available for common stock		$	301		$	—	$	301		$	499		$	—		$	499
Core Earnings3							$	248								$	199
Non-Core Earnings:
	Global Settlement							53									300
	Tax impact of health care legislation							—									—
Total SCE GAAP Earnings							$	301								$	499

38

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 three- and six-months periods ended June 30, 2009, respectively, were the following balances related to the Big 4 projects:

(in millions)	Three Months Ended June 30, 2009		Six Months Ended June 30, 2009
Operating revenue	$	131	$	274
Fuel		76		177
Operation and maintenance		25		46
Depreciation		8		17
Total operating expenses		109		240
Net income	$	22	$	34

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 ($27 million for both operating revenue and total expenses for the three months ended June 30, 2009 and $49 million for both operating revenue and total expenses for the six months ended June 30, 2009) were reclassified from cost-recovery activities to utility earnings activities consistent with the 2010 regulatory recovery mechanism.

³

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

Utility Earning Activities

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $55 million primarily due to the following:

•

$40 million increase related to implementation of the 2009 GRC (effective January 1, 2009) which authorized a 4.25% increase in 2010 authorized revenue.

•

$15 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.

•

$5 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).

•

Higher operation and maintenance expense of $21 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:

•

$15 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, increases in preventive maintenance work and training costs.

•

$10 million of higher expenses related to higher general liability insurance, a nuclear insurance refund received in 2009, and higher injury and damage claims.



Partially offset by:

•

$10 million of lower generation expenses primarily related to a $15 million hydrogen energy project payment made in the second quarter of 2009, which was subsequently approved for balancing account treatment in December 2009.

39

•

Higher depreciation expense of $31 million primarily resulting from increased capital investments including capitalized software costs.

See "—Income Taxes" below for discussion of lower income taxes during the three months ended June 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:

•

Higher purchased power expense of $29 million primarily due to: higher QF purchased power expense of $120 million primarily due to higher natural gas prices and higher kWh purchases. This was partially offset by lower bilateral energy purchase expense of $30 million primarily due to decreased kWh purchases. Realized losses on economic hedging activities were $38 million in 2010 and $96 million in 2009. Changes in realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than contract prices.

•

Higher fuel expense of $14 million primarily due to higher costs at Mountainview of $15 million resulting from higher natural gas prices.

40

Six Months Ended June 30, 2010 versus June 30, 2009

		Six Months Ended June 30, 2010									Six Months Ended June 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		$	2,573		$	1,833		$	4,406		$	2,457		$	2,005		$	4,462
Fuel and purchased power			—			1,395			1,395			—			1,480			1,480
Operation and maintenance			1,057			411			1,468			958			462			1,420
Depreciation, decommissioning and amortization			605			24			629			548			26			574
Property and other taxes			129			1			130			127			—			127
Gain on sale of assets			—			—			—			—			(1	)		(1	)
Total operating expenses			1,791			1,831			3,622			1,633			1,967			3,600
Operating income			782			2			784			824			38			862
Net interest expense and other			(157	)		(2	)		(159	)		(169	)		(4	)		(173	)
Income before income taxes			625			—			625			655			34			689
Income tax expense (benefit)			134			—			134			(77	)		—			(77	)
Net income			491			—			491			732			34			766
Net income attributable to noncontrolling interests			—			—			—			—			34			34
Dividends on preferred and preference stock not subject to mandatory redemption			26			—			26			25			—			25
Net income available for common stock		$	465		$	—		$	465		$	707		$	—		$	707
Core Earnings3								$	451								$	407
Non-Core Earnings:
	Global Settlement								53									300
	Tax impact of health care legislation								(39	)								—
Total SCE GAAP Earnings								$	465								$	707

¹

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

²

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

³

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

Utility Earning Activities

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $116 million primarily due to the following:

•

$80 million increase related to implementation of the 2009 GRC (effective January 1, 2009) which authorized a 4.25% increase in 2010 authorized revenue.

•

$30 million increase related to the 2009 and 2010 FERC rate cases effective March 1, 2009 and March 1, 2010, respectively (see "SCE: Liquidity and Capital Resources—Regulatory Proceedings—2010 FERC Rate Case" for further discussion).

41

•

$15 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 $99 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:

•

$45 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, increases in preventive maintenance work, line clearing costs and training costs.

•

$30 million of higher expenses related to higher general liability insurance, a nuclear insurance refund received in 2009, and higher injury and damage claims.

•

$5 million of higher 2010 generation expenses reflecting $10 million primarily due to additional work identified during the San Onofre Unit 2 scheduled outage and $10 million 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 balancing account treatment 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 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 and the installation of the final two steam generators at San Onofre Unit 3 is expected to begin in late 2010. 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, SCE is subject to the jurisdiction of the NRC with respect to its San Onofre and Palo Verde Nuclear Generating Stations. San Onofre is currently addressing a number of regulatory and performance issues, and the NRC has required SCE to take actions to provide greater assurance of compliance by San Onofre personnel with applicable NRC requirements and procedures. SCE continues to implement plans to address the identified issues. The NRC has continued to affirm that San Onofre has been operated and is being operated safely; however, a number of these issues remain outstanding, and additional issues have been identified. The cumulative impact of these regulatory and performance issues has been an increase in management focus and other resources applied at San Onofre. To the extent that these issues persist, the likelihood of further required action, and associated potential for effects on costs and operations, will increase.

•

Higher depreciation expense of $57 million primarily related to increased capital investments including capitalized software costs.

42

•

Lower net interest expense and other of $12 million primarily related to higher capitalized cost of equity and debt (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 six months ended June 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:

•

Higher purchased power expense of $96 million primarily related to: higher QF purchased power expense of $250 million primarily due to higher natural gas prices and higher kWh purchases; and higher ISO-related energy costs of $75 million, including replacement power costs related to the San Onofre Unit 2 scheduled outage. This was partially offset by lower bilateral energy purchase expense of $90 million primarily due to decreased kWh purchases. Realized losses on economic hedging activities were $62 million in 2010 and $194 million in 2009. Changes in realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than contract prices.

•

Lower fuel expense of $4 million primarily related to lower costs at Four Corners (coal) of $10 million and lower costs at San Onofre Unit 2 of $5 million both resulting from the outages described above. These decreases were offset by higher costs at Mountainview of $15 million resulting from higher natural gas prices.

Supplemental Operating Revenue Information

SCE's total consolidated operating revenue was $2.2 billion and $2.3 billion for the three months ended June 30, 2010 and 2009, respectively, of which $2.4 billion and $2.3 billion was related to retail billed and unbilled revenue (excluding wholesale sales and balancing account (over)/undercollections) for the same respective periods. SCE's total consolidated operating revenue was $4.4 billion and $4.5 billion for the six months ended June 30, 2010 and 2009, respectively, of which $4.4 billion and $4.2 billion was related to retail billed and unbilled revenue (excluding wholesale sales and balancing account (over)/undercollections) for the same respective periods. Retail billed and unbilled revenue increased $57 million and $201 million for the three- and six-month periods ended June 30, 2010, respectively, compared to the same periods in 2009. The quarter and year-to-date increases reflect a rate increase of $126 million and $305 million, respectively, and a sales volume decrease of $69 million and $104 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 slightly milder weather experienced during the second quarter of 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).

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.

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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 $286 million and $582 million for the three- and six-month periods ended June 30, 2010, respectively, and $391 million and $896 million for the three- and six-month periods ended June 30, 2009, respectively. Effective January 1, 2010, the CDWR-related rates were decreased primarily to refund CDWR overcollections to customers.

Income Taxes

SCE's income tax expense from continuing operations increased $203 million and $211 million during the three- and six-month periods ended June 30, 2010, respectively. The 2010 income tax expense reflects: a $39 million non-cash charge recorded in the first quarter related to the federal health care legislation enacted in March 2010; 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; and a $53 million earnings benefit recorded in the second quarter resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002. During the second quarter of 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 June 30, 2010, SCE had approximately $91 million of cash and equivalents and short-term investments. As of June 30, 2010, SCE's long-term debt, including current maturities of long-term debt, was $7.1 billion.

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

(in millions)	Credit Facilities1
Commitment	$	2,894
Outstanding borrowings		(215	)
Outstanding letters of credit		(11	)
Amount available	$	2,668

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

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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 under which SCE expected to receive a $27 million final payment in late 2010. SCE expects a CPUC decision on the final payment, if any, in the second half of 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 June 30, 2010, SCE's 13-month weighted-average common equity component of total capitalization was 51% resulting in the capacity to pay $461 million in additional dividends.

SCE paid dividends of $100 million to its parent, Edison International, in January 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.

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)	June 30, 2010
Collateral posted as of June 30, 20101	$	22
Incremental collateral requirements resulting from a potential downgrade of SCE's credit rating to below investment grade		180
Total posted and potential collateral requirements2	$	202

¹

Collateral posted consisted of $8 million which was offset against net derivative liabilities and $14 million provided to counterparties and other brokers (consisting of $4 million in cash reflected in "Margin and collateral deposits" on the consolidated balance sheets and $10 million in letters of credit).

²

Total posted and potential collateral requirements may increase by an additional $13 million, based on SCE's forward position as of June 30, 2010, due to adverse market price movements over the remaining life of the existing contracts using a 95% confidence level.

45

Historical Consolidated Cash Flow

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

Condensed Consolidated Statement of Cash Flows

	Six Months Ended June 30,
(in millions)	2010			2009
Cash flows provided by operating activities	$	1,095		$	2,054
Cash flows provided (used) by financing activities		465			(1,694	)
Cash flows used by investing activities		(1,937	)		(1,517	)
Net decrease in cash and equivalents	$	(377	)	$	(1,157	)

Cash Flows Provided by Operating Activities

Cash provided by operating activities decreased $959 million in the second quarter of 2010, compared to the second quarter of 2009 primarily due to the impacts of the Global Settlement, which resulted in a net tax allocation payment received in 2009 from Edison International of $875 million and an increase in deferred tax liabilities related to the settlement of affirmative claims. The 2010 change was also due to the timing of cash receipts and disbursements related to working capital items and a decrease in pre-tax income.

Cash Flows Provided (Used) by Financing Activities

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

•

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

•

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

•

Issued $215 million of short-term debt to fund interim working capital requirements.

•

Repaid $250 million of senior unsecured notes.

•

Paid $100 million in dividends to Edison International.

Financing activities for the first six 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 tem debt.

•

Repaid $150 million of first and refunding mortgage bonds.

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•

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 six 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 $100 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 $1.8 billion and $1.4 billion for the six months ended June 30, 2010 and 2009, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $97 million and $105 million for the six months ended June 30, 2010 and 2009, respectively.

Contractual Obligations and Contingencies

Contractual Obligations

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—Commitments and —Other Commitments."

Contingencies

Developments related to SCE's 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 June 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 "SCE: Market Risk Exposures—Commodity Price Risk" in the year-ended 2009 MD&A.

Interest Rate Risk

At June 30, 2010, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $8.1 billion, compared to a carrying value of $7.1 billion. At June 30, 2010, SCE

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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.

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."

	June 30, 2010					December 31, 2009
(in millions)	Assets		Liabilities			Assets		Liabilities
Electricity options, swaps and forward arrangements	$	1	$	89		$	1	$	25
Natural gas options, swaps and forward arrangements		84		280			86		171
Congestion revenue rights		190		—			217		—
Tolling arrangements1		—		1,006			43		402
Netting and collateral		—		(8	)		—		—
Total	$	275	$	1,367		$	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.

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The change in the fair value of derivative contracts for the six months ended June 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		(919	)
Purchases and settlements, net			70
Netting and collateral			8
Fair value of derivative contracts, net liability at June 30, 2010		$	(1,092	)

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, 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 lower forward heat rates (spread between electricity prices and natural gas prices) related to SCE's long-term contracts from new natural gas-fired generation facilities.

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 June 30, 2010, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:

	June 30, 2010
(in millions)	Exposure2		Collateral		Net Exposure
S&P Credit Rating1
A or higher	$	217	$	—	$	217
A-		—		—		—
BBB+		1		—		1
BBB		—		—		—
BBB-		—		—		—
Below investment grade and not rated		—		—		—
Total	$	218	$	—	$	218

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 purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheets, except for any related net accounts receivable.

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The credit risk exposure set forth in the above table is comprised of less than $1 million of net account receivables and $218 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

The CAISO comprises 87% 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 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."

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ITEM 6. EXHIBITS

10.1	Edison International Director Matching Gifts Program, as adopted June 24, 2010 (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2010)*
31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32	Statement Pursuant to 18 U.S.C. Section 1350
101	Financial statements from the quarterly report on Form 10-Q of Southern California Edison Company for the quarter ended June 30, 2010, filed on August 5, 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 Consolidated Financial Statements.

*

Incorporated by reference pursuant to Rule 12b-32.

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SIGNATURE

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

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

Date: August 5, 2010

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