SCE 10-Q Quarterly Report March 31, 2010

SOUTHERN CALIFORNIA EDISON CO

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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 March 31, 2010
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission File Number 1-2313

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


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

(626) 302-1212
(Registrant's telephone number, including area code)

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

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

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


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

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

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

Class		Outstanding at May 3, 2010

Common Stock, no par value		434,888,104

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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			9
	Note 5. Compensation and Benefit Plans			10
	Note 6. Commitments and Contingencies			12
	Note 7. Consolidated Statement of Changes in Equity			17
	Note 8. Supplemental Cash Flows Information			18
	Note 9. Fair Value Measurements			18
	Note 10. Regulatory Assets and Liabilities			24
	Note 11. Other Income and Expenses			25
	Note 12. Variable Interest Entities			25
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				28
	FORWARD-LOOKING STATEMENTS			28
	MANAGEMENT OVERVIEW			29
	Introduction			29
	Highlights of Operating Results			30
	SCE Capital Program			30
	Environmental Developments			31
		California Renewable Energy Developments		31
		Once-Through Cooling		31
	RESULTS OF OPERATIONS			32
	Electric Utility Results of Operations			33
		Utility Earning Activities		34
			2010 vs. 2009	34
		Utility Cost-Recovery Activities		34
			2010 vs. 2009	34
		Supplemental Operating Revenue Information		35
		Effective Income Tax Rates		35

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	LIQUIDITY AND CAPITAL RESOURCES			35
	Available Liquidity			36
		Debt Covenant		36
	Regulatory Proceedings			36
		Energy Efficiency Risk/Reward Incentive Mechanism		36
		2010 FERC Rate Case		36
	Dividend Restrictions			36
	Margin and Collateral Deposits			37
	Historical Consolidated Cash Flow			37
		Condensed Consolidated Statement of Cash Flows		37
			Cash Flows Provided by Operating Activities	37
			Cash Flows Provided (Used) by Financing Activities	38
			Cash Flows Used by Investing Activities	38
	Contractual Obligations and Contingencies			38
		Contractual Obligations		38
		Contingencies		39
			Environmental Remediation	39
	MARKET RISK EXPOSURES			39
	Interest Rate Risk			39
	Commodity Price Risk			39
		Natural Gas and Electricity Price Risk		39
	Credit Risk			40
	NEW ACCOUNTING GUIDANCE			41
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				41
ITEM 4T. CONTROLS AND PROCEDURES				41
	Disclosure Controls and Procedures			41
	Internal Control Over Financial Reporting			41
PART II. OTHER INFORMATION				41
ITEM 1. LEGAL PROCEEDINGS				41
	Navajo Nation Litigation			41
ITEM 6. EXHIBITS				41
SIGNATURE				43

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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
EME		Edison Mission Energy
ERRA		energy resource recovery account
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGIC		Financial Guarantee Insurance Company
Four Corners		coal-fired electric generating facility located in Farmington, New Mexico where SCE holds a 48% ownership interest in Units 4 and 5
FTRs		firm transmission rights
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
Illinois EPA		Illinois Environmental Protection Agency
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		Mohave Generating Station
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

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NOx		nitrogen oxide
NRC		Nuclear Regulatory Commission
NSR		New Source Review
Palo Verde		Palo Verde Nuclear Generating Station
PBOP(s)		postretirement benefits other than pension(s)
PBR		Performance-based ratemaking
PG&E		Pacific Gas & Electric Company
POD		Presiding Officer's Decision
PX		California Power Exchange
QF(s)		qualifying facility(ies)
RICO		Racketeer Influenced and Corrupt Organization
ROE		return on equity
S&P		Standard & Poor's Ratings Services
San Onofre		San Onofre Nuclear Generating Station
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)
SO ₂		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)

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



Consolidated Statements of Income		Southern California Edison Company
			Three Months Ended March 31,
(in millions)			2010			2009

			(Unaudited)
Operating revenue			$	2,159		$	2,189

Fuel				81			199
Purchased power				608			540
Operation and maintenance				713			658
Depreciation, decommissioning and amortization				309			285
Property and other taxes				68			66

Total operating expenses				1,779			1,748

Operating income				380			441
Interest income				1			4
Other income				34			26
Interest expense – net of amounts capitalized				(99	)		(109	)
Other expenses				(10	)		(8	)

Income before income taxes				306			354
Income tax expense				129			121

Net income				177			233
Less: Net income attributable to noncontrolling interests				—			12
	Dividends on preferred and preference stock not subject to mandatory redemption			13			13

Net income available for common stock			$	164		$	208

Consolidated Statements of Comprehensive Income

			Three Months Ended March 31,
(in millions)			2010		2009

			(Unaudited)
Net income			$	177	$	233
Other comprehensive income, net of tax:
	Pension and postretirement benefits other than pensions:
		Amortization of net loss included in net income		1		—

Comprehensive income				178		233
Less: Comprehensive income attributable to noncontrolling interests				—		12

Comprehensive income attributable to SCE			$	178	$	221

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)			March 31, 2010			December 31, 2009

			(Unaudited)
ASSETS
Cash and equivalents			$	66		$	462
Short-term investments				9			9
Receivables, less allowances of $53 for uncollectible accounts at both dates				626			719
Accrued unbilled revenue				360			347
Inventory				320			337
Derivative assets				130			160
Regulatory assets				303			120
Deferred income taxes				—			78
Other current assets				229			97

Total current assets				2,043			2,329

Nonutility property – less accumulated depreciation of $92 and $744 at respective dates				70			324
Nuclear decommissioning trusts				3,248			3,140
Other investments				75			67

Total investments and other assets				3,393			3,531

Utility plant, at original cost:
	Transmission and distribution			22,674			22,214
	Generation			2,680			2,667
Accumulated depreciation				(6,064	)		(5,921	)
Construction work in progress				2,790			2,701
Nuclear fuel, at amortized cost				314			305

Total utility plant				22,394			21,966

Derivative assets				141			187
Regulatory assets				4,675			4,139
Other long-term assets				329			322

Total long-term assets				5,145			4,648






Total assets			$	32,975		$	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)		March 31, 2010			December 31, 2009

		(Unaudited)
LIABILITIES AND EQUITY
Short-term debt		$	180		$	—
Current portion of long-term debt			—			250
Accounts payable			897			1,282
Accrued taxes			39			9
Accrued interest			114			162
Customer deposits			234			238
Derivative liabilities			178			102
Regulatory liabilities			288			367
Deferred income taxes			47			—
Other current liabilities			427			637

Total current liabilities			2,404			3,047

Long-term debt			6,984			6,490

Deferred income taxes			3,796			3,651
Deferred investment tax credits			95			97
Customer advances			112			119
Derivative liabilities			920			496
Pensions and benefits			1,702			1,681
Asset retirement obligations			3,229			3,198
Regulatory liabilities			3,521			3,328
Other deferred credits and other long-term liabilities			1,680			1,652

Total deferred credits and other liabilities			15,055			14,222

Total liabilities			24,443			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			557			551
Accumulated other comprehensive loss			(18	)		(19	)
Retained earnings			4,905			4,746

Total common shareholder's equity			7,612			7,446

Preferred and preference stock not subject to mandatory redemption			920			920
Noncontrolling interests			—			349

Total equity			8,532			8,715

Total liabilities and equity		$	32,975		$	32,474

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

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Consolidated Statements of Cash Flows		Southern California Edison Company
			Three Months Ended March 31,
(in millions)			2010			2009

			(Unaudited)
Cash flows from operating activities:
Net income			$	177		$	233
Adjustments to reconcile to net cash provided by operating activities:
	Depreciation, decommissioning and amortization			309			285
	Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)			38			32
	Other amortization			21			25
	Stock-based compensation			4			3
	Deferred income taxes and investment tax credits			189			122
Changes in operating assets and liabilities:
	Receivables			62			23
	Inventory			1			43
	Margin and collateral deposits – net of collateral received			(2	)		(20	)
	Other current assets			(151	)		18
	Accounts payable			(158	)		(170	)
	Accrued taxes			29			26
	Other current liabilities			(153	)		(78	)
	Derivative assets and liabilities – net			577			(348	)
	Regulatory assets and liabilities – net			(636	)		244
	Other assets			(14	)		(13	)
	Other liabilities			20			(19	)

Net cash provided by operating activities				313			406

Cash flows from financing activities:
Long-term debt issued				500			750
Long-term debt issuance costs				(11	)		(10	)
Long-term debt repaid				(252	)		(151	)
Bonds repurchased				—			(219	)
Short-term debt financing – net				180			(335	)
Stock-based compensation – net				1			2
Distributions to noncontrolling interest				—			(25	)
Dividends paid				(113	)		(113	)

Net cash provided (used) by financing activities				305			(101	)

Cash flows from investing activities:
Capital expenditures				(867	)		(690	)
Proceeds from sale of nuclear decommissioning trust investments				286			658
Purchases of nuclear decommissioning trust investments and other				(335	)		(700	)
Sales of short-term investments				1			—
Purchases of short-term investments				(1	)		(1	)
Customer advances for construction and other investments				(6	)		(6	)

Net cash used by investing activities				(922	)		(739	)

Effect of deconsolidation of variable interest entities				(92	)		—

Net decrease in cash and equivalents				(396	)		(434	)
Cash and equivalents, beginning of period				462			1,611

Cash and equivalents, end of period			$	66		$	1,177

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 its 2009 Annual Report on 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 months ended March 31, 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 $40 million and $360 million at March 31, 2010 and December 31, 2009, respectively. The carrying value of cash equivalents equals the fair value, as all investments have maturities of less than three months. For further discussion of money market funds, see Note 9.

SCE has a cash management program under which the ending daily cash balance in its primary disbursement accounts are temporarily invested until required for check clearing. SCE reclassified $238 million and $224 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at March 31, 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

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

(in millions)		March 31, 2010		December 31, 2009


		(Unaudited)
Collateral provided to counterparties:
	Offset against derivative liabilities	$	10	$	—
	Reflected in other current assets		5		6
Collateral received from counterparties:
	Reflected in other current liabilities		56		59

New Accounting Guidance

Accounting Guidance Adopted in 2010

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

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

Fair Value Measurements and Disclosures

The FASB issued an accounting standards update that provides for new disclosure requirements related to fair value measurements. Requirements, 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 were effective after March 31, 2010 are not expected to have a material effect on SCE's consolidated results of operations, financial position or cash flows.

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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:

		March 31, 2010		December 31, 2009


Commodity	Unit of Measure	Economic Hedges		Economic Hedges

		(Unaudited)
Electricity options, swaps and forward arrangements	GWh		14,943		14,868
Natural gas options, swaps and forward arrangements	Bcf		251		266
Congestion revenue rights	GWh		180,518		195,367
Tolling arrangements ¹	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 March 31, 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	$	132		$	141	$	273		$	190		$	920	$	1,110		$	837
Netting and collateral		(2	)		—		(2	)		(12	)		—		(12	)		(10	)

Total	$	130		$	141	$	271		$	178		$	920	$	1,098		$	827

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
Netting and collateral		—		—		—		—		—		—		—

Total	$	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 from ratepayers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are deferred and are not recognized as purchased-power expense and therefore do not affect earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.

The following table summarizes the components of economic hedging activity:

	Three Months Ended March 31,

(in millions)	2010			2009

	(Unaudited)
Realized gain (loss)	$	(24	)	$	(98	)
Unrealized gain (loss)		(581	)		333

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Contingent Features/Credit-Related Exposure

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

Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from each of the major credit rating agencies, referred to as a "credit-risk-related contingent feature." If SCE's credit rating were to fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The aggregate fair value of all derivative liabilities with these credit-risk-related contingent features was $213 million and $91 million, as of March 31, 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 March 31, 2010, SCE would be required to post $16 million of 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. The bond proceeds were used to repay commercial paper borrowings and for general corporate purposes.

Credit Agreements and Short-Term Debt

Short-term debt is generally used to finance fuel inventories, balancing account under-collections and general, temporary cash requirements including power purchase payments. At March 31, 2010, the outstanding short-term debt was $180 million at a weighted-average interest rate of .28%. This short-term debt was supported by a $2.4 billion credit line. At December 31, 2009, the outstanding short-term debt was zero.

At March 31, 2010, letters of credit under SCE's credit facility aggregated $82 million and were scheduled to expire in 2010.

Note 4. Income Taxes

SCE's effective tax rates were 42% and 35% (excluding income attributable to non-controlling interests) for the three months ended March 31, 2010 and 2009, respectively. The increase in the effective tax rate was primarily due to a $39 million non-cash charge recorded in the first quarter of 2010 to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010, partially offset by higher property-related flow-through tax deductions in 2010. 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.

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

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

Accounting for Uncertainty in Income Taxes

Unrecognized tax benefits increased $123 million during the first quarter of 2010 mainly as a result of tax positions taken for a prior period.

Note 5. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

For the three months ended March 31, 2010, SCE made 2010 plan year contributions of $20 million and expects to make $61 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 March 31,

(in millions)	2010			2009

	(Unaudited)
Service cost	$	29		$	27
Interest cost		49			48
Expected return on plan assets		(49	)		(40	)
Amortization of prior service cost		2			4
Amortization of net loss		6			13

Expense under accounting standards		37			52
Regulatory adjustment – deferred		(14	)		(37	)

Total expense recognized	$	23		$	15

Postretirement Benefits Other Than Pensions

For the three months ended March 31, 2010, SCE made 2010 plan year contributions of $4 million and expects to make $39 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.

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Expense components are:

	Three Months Ended March 31,

(in millions)	2010			2009

	(Unaudited)
Service cost	$	7		$	10
Interest cost		30			34
Expected return on plan assets		(25	)		(21	)
Amortization of prior service cost (credit)		(9	)		(7	)
Amortization of net loss		8			15

Total expense	$	11		$	31

Stock-Based Compensation

During the first quarter of 2010, Edison International granted its 2010 stock-based compensation awards, 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 $3 million for the three months ended March 31, 2010 and 2009, respectively. The income tax benefit recognized in the consolidated statements of income was $2 million and $1 million for the three months ended March 31, 2010 and 2009, respectively. Consistent with SCE's 2009 GRC, no stock-based compensation was capitalized beginning in 2009. Excess tax benefits included in "Stock-based compensation – net" in the financing section of the consolidated statements of cash flows were $1 million and $2 million for the three months ended March 31, 2010 and 2009, respectively.

Stock Options

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

				Weighted-Average

	Stock Options			Exercise Price		Remaining Contractual Term (Years)		Aggregate Intrinsic Value

	(Unaudited)
Outstanding at December 31, 2009		8,749,015		$	31.91
Granted		2,005,056			33.30
Forfeited		(6,662	)		30.52
Exercised		(112,315	)		23.86
Affiliate transfers – net		23,408			34.81

Outstanding at March 31, 2010		10,658,502			32.26		6.99

Vested and expected to vest at March 31, 2010		10,374,048			32.26		6.93	$	56,649,657

Exercisable at March 31, 2010		5,851,805			32.31		5.34		37,437,597

SCE's cash outflows to purchase Edison International shares in the open market to settle stock options exercised were $4 million and $3 million for the three months ended March 31, 2010 and 2009,

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respectively. Cash inflows from participants to exercise stock options were $3 million and $2 million for the three months ended March 31, 2010 and 2009, respectively. The tax benefit realized from options exercised was less than $1 million for each of the three months ended March 31, 2010 and 2009.

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		75,916			32.50
Forfeited		(32,149	)		57.77
Affiliate transfers – net		801			37.80

Nonvested at March 31, 2010		217,172			32.25

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		75,916
Forfeited		(32,149	)
Affiliate transfers – net		801

Nonvested at March 31, 2010		217,172		$	28.04

There were no performance shares settled in 2009 or 2010.

Note 6. Commitments and Contingencies

Other Commitments

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

Indemnities

Indemnity Provided as Part of the Acquisition of Mountainview

In connection with the acquisition of 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.

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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 guarantee.

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 Remediation

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

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

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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 March 31, 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 $171 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 less than $1 million and $3 million for the three months ended March 31, 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 active examination by the IRS for tax years 2003 through 2006 and are subject to examination through tax year 2009. Edison International's California and other state income tax returns remain open for tax years 1986 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 revenue requirement by $107 million, or 24%, over the 2009 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 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. SCE may seek a rehearing of the order. 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. The 2010 CWIP revenue requirements are expected to be collected in rates beginning on June 1, 2010. The collected 2008 and 2009 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

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any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site, all nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.

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

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by utilities 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.

On January 29, 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. The trial was completed in April 2009 but no decision has been issued. SCE cannot predict the outcome of this proceeding or when a decision will be issued by the Court.

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Note 7. Consolidated Statement of Changes in Equity

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

	Equity Attributable to SCE

(in millions)	Common Stock		Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Preferred and Preference Stock		Noncontrolling Interest			Total Equity

	(Unaudited)
Balance at December 31, 2009	$	2,168	$	551	$	(19	)	$	4,746		$	920	$	349		$	8,715
Net income		—		—		—			177			—		—			177
Other comprehensive income		—		—		1			—			—		—			1
Deconsolidation of variable interest entities (see Note 12)		—		—		—			—			—		(349	)		(349	)
Dividends declared on preferred and preference stock not subject to mandatory redemption		—		—		—			(13	)		—		—			(13	)
Stock-based compensation – net		—		2		—			(1	)		—		—			1
Noncash stock-based compensation and other		—		4		—			(4	)		—		—			—

Balance at March 31, 2010	$	2,168	$	557	$	(18	)	$	4,905		$	920	$	—		$	8,532

The following table provides changes in equity for the three months ended March 31, 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		—		—		—			221			—		12			233
Distributions to noncontrolling interests		—		—		—			—			—		(25	)		(25	)
Dividends declared on preferred and preference stock not subject to mandatory redemption		—		—		—			(13	)		—		—			(13	)
Stock-based compensation – net		—		2		—			—			—		—			2
Noncash stock based compensation and other		—		2		—			(3	)		—		—			(1	)

Balance at March 31, 2009	$	2,168	$	536	$	(14	)	$	4,032		$	920	$	367		$	8,009

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Note 8. Supplemental Cash Flows Information

The following is SCE's supplemental cash flows information:

		Three Months Ended March 31,

(in millions)		2010		2009

		(Unaudited)
Cash payments (receipts) for interest and taxes
	Interest – net of amounts capitalized	$	132	$	119
	Tax payments (receipts)		2		(24	)
Noncash investing and financing activities
	Deconsolidation of variable interest entities:
	Assets other than cash	$	306	$	—
	Liabilities and noncontrolling interests		398		—
Dividends declared but not paid
	Preference stock	$	8	$	8

Note 9. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value for a liability should reflect the entity's non-performance 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 traded or over-the-counter traded.

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 financial natural gas swaps, fixed to

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floating swaps, and natural gas physical trades for which SCE obtains the applicable Henry Hub and basis 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. SCE has Level 3 fixed to floating swaps for which SCE obtains the applicable Henry Hub and basis forward market prices from the New York Mercantile Exchange. However, these swaps have contract terms that extend beyond observable market data and the unobservable inputs incorporated in the fair value determination are considered significant compared to the overall swap's fair value.

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 is 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 $2 million and $11 million, respectively at March 31, 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.

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

			As of March 31, 2010

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

			(Unaudited)
Assets at Fair Value
	Money market funds ²		$	40	$	—		$	—		$	—		$	40

	Derivative contracts:
		Natural Gas		—		3			71			(2	)		72
		CRRs		—		—			199						199

		Sub-total of derivative contracts		—		3			270			(2	)		271

	Long-term disability plan			9		—			—			—			9

	Nuclear decommissioning trusts:
		Stocks ³		1,846		—			—			—			1,846
		Municipal bonds		—		652			—			—			652
		Corporate bonds ⁴		—		403			—			—			403
		U.S. government and agency securities		253		49			—			—			302
		Short-term investments, primarily cash equivalents ⁵		12		23			—			—			35

		Sub-total of nuclear decommissioning trusts		2,111		1,127			—			—			3,238

Total assets ⁶			$	2,160	$	1,130		$	270		$	(2	)	$	3,558

Liabilities at Fair Value
	Derivative contracts:
		Electricity	$	—	$	—		$	(82	)	$	—		$	(82	)
		Natural Gas		—		(244	)		(52	)		12			(284	)
		Tolling		—		—			(732	)		—			(732	)

		Sub-total of derivative contracts		—		(244	)		(866	)		12			(1,098	)

Net assets (liabilities)			$	2,160	$	886		$	(596	)	$	10		$	2,460

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			As of December 31, 2009

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

			(Unaudited)
Assets at Fair Value
	Money market funds ²		$	360	$	—		$	—		$	—	$	360

	Derivative contracts:
		Electricity		—		—			1			—		1
		Natural Gas		—		10			76			—		86
		CRRs		—		—			217			—		217
		Tolling		—		—			43			—		43

		Sub-total of derivative contracts		—		10			337			—		347

	Long-term disability plan			8		—			—			—		8

	Nuclear decommissioning trusts:
		Stocks ³		1,772		—			—			—		1,772
		Municipal bonds		—		634			—			—		634
		Corporate bonds ⁴		—		393			—			—		393
		U.S. government and agency securities		240		68			—			—		308
		Short-term investments, primarily cash equivalents ⁵		1		14			—			—		15

		Sub-total of nuclear decommissioning trusts		2,013		1,109			—			—		3,122

Total assets ⁶			$	2,381	$	1,119		$	337		$	—	$	3,837

Liabilities at Fair Value
	Derivative contracts:
		Electricity	$	—	$	—		$	(25	)	$	—	$	(25	)
		Natural Gas		—		(150	)		(21	)		—		(171	)
		Tolling		—		—			(402	)		—		(402	)

		Sub-total 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 March 31, 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 March 31, 2010 and December 31, 2009, this category included $52 million and $50 million, respectively, for collateralized mortgage obligations and other asset backed securities.
⁵: Excludes net assets of $10 million and $18 million of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases at March 31, 2010 and December 31, 2009, respectively.
⁶: Excludes $32 million of cash surrender value of life insurance investments for deferred compensation at March 31, 2010 and December 31, 2009.

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

		Three Months Ended March 31,

(in millions)		2010			2009

		(Unaudited)
Fair value of derivative contracts, net liability at beginning of period		$	(111	)	$	(518	)
Total realized/unrealized gains (losses):
	Included in regulatory assets and liabilities ¹		(487	)		388
Purchases and settlements, net			2			4
Transfers into Level 3			—			—
Transfers out of Level 3			—			—

Fair value, net liability at end of period		$	(596	)	$	(126	)

Change during the period in unrealized gains (losses) related to assets and liabilities held at the end of period		$	(468	)	$	391

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 quarter 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 Dates ¹		March 31, 2010		December 31, 2009		March 31, 2010		December 31, 2009

			(Unaudited)
Stocks		–	$	828	$	822	$	1,846	$	1,772
Municipal bonds		2010 – 2047		559		545		652		634
Corporate bonds		2010 – 2044		325		309		403		393
U.S. government and agency securities		2010 – 2039		284		287		302		308
Short-term investments and receivables/payables		2010		43		33		45		33

Total			$	2,039	$	1,996	$	3,248	$	3,140

¹: Maturity dates as of March 31, 2010.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Realized gains were $21 million and $74 million for the three months ended March 31, 2010 and 2009, respectively. Realized losses were zero and $62 million for the three months

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ended March 31, 2010 and 2009, respectively. Proceeds from sales of securities (which are reinvested) were $286 million and $658 million for the three months ended March 31, 2010 and 2009, respectively. Unrealized holding gains, net of losses, were $1.2 billion and $1.1 billion at March 31, 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 March 31,

(in millions)	2010			2009

	(Unaudited)
Balance at beginning of period	$	3,140		$	2,524
Realized gains – net		21			12
Unrealized gains – net		62			(73	)
Other-than-temporary impairment		(3	)		(94	)
Interest, dividends, contributions and other		28			30

Balance at end of period	$	3,248		$	2,399

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:

	March 31, 2010				December 31, 2009


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

	(Unaudited)
Long-term debt, including current portion	$	6,984	$	7,368	$	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.

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Note 10. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)	March 31, 2010		December 31, 2009


	(Unaudited)
Current:
Regulatory balancing accounts	$	166	$	94
Energy derivatives		136		25
Other		1		1

		303		120

Long-term:
Regulatory balancing accounts		51		43
Deferred income taxes – net		1,640		1,561
Unamortized nuclear investment – net		325		340
Nuclear-related ARO investment – net		253		258
Unamortized coal plant investment – net		73		73
Unamortized loss on reacquired debt		282		287
Pensions and other postretirement benefits		1,009		1,014
Energy derivatives		826		357
Environmental remediation		39		36
Other		177		170

		4,675		4,139

Total Regulatory Assets	$	4,978	$	4,259

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	March 31, 2010		December 31, 2009


	(Unaudited)
Current:
Regulatory balancing accounts	$	282	$	363
Other		6		4

		288		367

Long-term:
Regulatory balancing accounts		750		642
ARO		230		171
Costs of removal		2,541		2,515

		3,521		3,328

Total Regulatory Liabilities	$	3,809	$	3,695

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Note 11. Other Income and Expenses

Other income and expenses are as follows:

	Three Months Ended March 31,

(in millions)	2010		2009

	(Unaudited)
Other Income:
Equity AFUDC	$	27	$	16
Increase in cash surrender value of life insurance policies		6		6
Other		1		4

Total other income	$	34	$	26

Other Expense:
Civic, political and related activities and donations	$	5	$	4
Other		5		4

Total other expense	$	10	$	8

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 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

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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 non performance 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, so there is no significant potential maximum exposure to loss as a result of its involvement with the VIEs. For contracts accounted for as a derivative, the potential maximum exposure is limited to the derivative asset balance in the tables below. The aggregate capacity dedicated to SCE for these VIE projects was 1,749 MW at March 31, 2010 and the amounts that SCE paid to these projects were $125 million and $116 million for the three-month periods ended March 31, 2010 and March 31, 2009, respectively. These amounts are recoverable in customer rates.

The following table summarizes as of March 31, 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	$	—	$	—	$	32	$	700	$	—
Accounts Payable		—		—		40		—		—

Total	$	—	$	—	$	72	$	700	$	—

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

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

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

	December 31, 2009

(in millions)	Electric Utility		VIEs		Eliminations			SCE

	(Unaudited)
Cash and equivalents	$	370	$	92	$	—		$	462
Accounts receivable – net		689		62		(32	)		719
Inventory		321		16		—			337
Other current assets		94		3		—			97
Nonutility property – net of accumulated depreciation		71		253		—			324
Other long-term assets		318		4		—			322

Total assets	$	32,076	$	430	$	(32	)	$	32,474

Accounts payable	$	1,031	$	59	$	(32	)	$	1,058
Other current liabilities		632		5		—			637
Asset retirement obligations		3,181		17		—			3,198
Noncontrolling interest		—		349		—			349

Total liabilities and equity	$	32,076	$	430	$	(32	)	$	32,474

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

	Three Months Ended March 31, 2009

(in millions)	Electric Utility			VIEs			Eliminations			SCE

	(Unaudited)
Operating revenue	$	2,129		$	143		$	(83	)	$	2,189

Fuel		97			102			—			199
Purchased power		623			—			(83	)		540
Operation and maintenance		637			21			—			658
Depreciation, decommissioning and amortization		277			8			—			285
Property and other taxes		66			—			—			66

Total operating expenses		1,700			131			(83	)		1,748

Operating income		429			12			—			441
Interest income		4			—			—			4
Other income		26			—			—			26
Interest expense – net of amounts capitalized		(109	)		—			—			(109	)
Other expenses		(8	)		—			—			(8	)
Income tax expense		(121	)		—			—			(121	)

Net income		221			12			—			233
Less: Net income attributable to noncontrolling interest		—			(12	)		—			(12	)
Dividends on preferred and preference stock not subject to mandatory redemption		(13	)		—			—			(13	)

Net income available for common stock	$	208		$	—		$	—		$	208

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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;
•: 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;

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•: effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
•: potential for penalties or disallowances caused by 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;
•: risk of counterparty default in hedging transactions or power-purchase and fuel contracts;
•: 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 SCE's Annual Report on Form 10-K for the year-ended December 31, 2009 (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 months ended March 31, 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 months ended March 31, 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.

MANAGEMENT OVERVIEW

Introduction

This overview is presented in three sections:

•: Highlights of operating results,
•: SCE capital program, and
•: Environmental developments.

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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 March 31,

(in millions)		2010			2009		Change

Net income available for common stock		$	164		$	208	$	(44	)
Non-Core Items
	Tax impact of health care legislation		(39	)		—		(39	)

Core Earnings		$	203		$	208	$	(5	)

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 decreased from 2009 primarily due to higher operating expense, including the impact of curtailed spending in the first quarter of last year until the 2009 CPUC GRC decision was received in March 2009. This decrease was almost entirely offset by rate base growth and higher capitalized financing costs (AFUDC).

Consolidated non-core items for SCE included a non-cash charge of $39 million 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.

SCE Capital Program

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

•: Upgrading and constructing new transmission lines to expand capacity to utilize 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

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the steam generators at San Onofre Unit 2 and Unit 2 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 Edison SmartConnect™. During the first quarter SCE installed approximately 343,000 smart meters, with cumulative installations totaling approximately 495,000.

SCE continues to plan to utilize much of the cash generated from its operations and issuance of additional debt and preferred equity for its capital program. During the first quarter of 2010, SCE issued $500 million of long-term debt that matures in 2040.

SCE's capital investments (including accruals) during the first quarter of 2010 totaled $640 million. 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.

Environmental Developments

California Renewable Energy Developments

In March 2010, CARB issued its preliminary draft Renewable Electricity Standard that would require most retail sellers of electricity in California to procure 33% of their electricity from eligible renewable energy resources by 2020. CARB is seeking comments on its draft from stakeholders and plans to issue proposed regulations during the summer of 2010. 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

On May 4, 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 gas-fired 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-fuel plants that use ocean water in once-through cooling systems. As a consequence, system reliability and the cost of electricity may be impacted 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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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 or provide mechanisms to track and recover or refund differences in forecasted and actual amounts. Balancing accounts 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, public purpose related program costs (including energy efficiency and demand-side management programs), certain operation and maintenance expenses, and depreciation expense related to certain projects. There is no return for cost-recovery expenses.

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Electric Utility Results of Operations

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

		Three Months Ended March 31, 2010									Three Months Ended March 31, 2009


(in millions)		Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities ^1,2			Total Consolidated

Operating revenue		$	1,265		$	894		$	2,159		$	1,204		$	985		$	2,189

Fuel and purchased power			—			689			689			—			739			739
Operation and maintenance			519			194			713			441			217			658
Depreciation, decommissioning and amortization			300			9			309			273			12			285
Property taxes and other			68			—			68			66			—			66

Total operating expenses			887			892			1,779			780			968			1,748

Operating income			378			2			380			424			17			441
Net interest expense and other			(72	)		(2	)		(74	)		(82	)		(5	)		(87	)

Income before income taxes			306			—			306			342			12			354
Income tax expense			129			—			129			121			—			121

Net income			177			—			177			221			12			233
Net income attributable to noncontrolling interest			—			—			—			—			12			12
Dividends on preferred and preference stock not subject to mandatory redemption			13			—			13			13			—			13

Net income available for common stock		$	164		$	—		$	164		$	208		$	—		$	208

Core Earnings ³								$	203								$	208
Non-Core Earnings:
	Tax impact of health care legislation								(39	)								—

Total SCE GAAP Earnings								$	164								$	208

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 months ended March 31, 2009 were the following balances related to the Big 4 projects:

(in millions)		Three Months Ended March 31, 2009


Operating revenue			$ 143

Fuel			102
Operation and maintenance			21
Depreciation			8

Total operating expenses			131

Net Income			$ 12

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 ($22 million for both operating revenue and total expenses) 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."

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Utility Earning Activities

2010 vs. 2009

Utility earning activities were primarily affected by the following:

•

Higher operating revenue of $61 million primarily due to the following:

•: $40 million increase due to implementation of the 2009 GRC (effective January 1, 2009) which authorized a 4.25% increase in 2010 authorized revenue.
•: $25 million increase resulting from 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 $78 million including the impact of curtailed spending in the first quarter of 2009 until the 2009 CPUC GRC decision was received in March 2009. The increase in operation and maintenance expense was primarily in the following areas:

•: $30 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 and increases in preventive maintenance work.
•: $20 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.

The first two of the four replacement steam generators were installed in San Onofre Unit 2 in the first quarter of 2010 and the final two are expected to be installed in San Onofre Unit 3 in late 2010. 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.

•: Higher depreciation expense of $27 million primarily resulting from increased capital investments including capitalized software costs.
•: Lower net interest expense and other of $10 million primarily due 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.

Utility Cost-Recovery Activities

2010 vs. 2009

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 $68 million primarily due to: higher QF power-purchase expense of $130 million primarily due to higher natural gas prices and higher kWh purchases; and higher ISO-related energy costs of $70 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 $65 million primarily due to decreased kWh purchases. Realized losses on economic hedging

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activities were $24 million in 2010 and $98 million in 2009. Changes in realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than average fixed prices.

•: Lower fuel expense of $16 million primarily due to lower costs at Four Corners (coal) of $10 million resulting from an outage during the first quarter 2010 and lower costs at San Onofre Unit 2 of $5 million resulting from the first quarter 2010 outage described above.

Supplemental Operating Revenue Information

SCE's total consolidated operating revenue was $2.2 billion for both the three months ended March 31, 2010 and 2009, of which $2.0 billion and $1.9 billion were related to retail billed and unbilled revenue (excluding wholesale sales) for March 31, 2010 and 2009, respectively. During the first quarter of 2010, retail billed and unbilled revenue increased $145 million compared to the first quarter of 2009. The increase reflects a rate increase of $182 million and a sales volume decrease of $37 million. The rate increase was due to higher system average rates for the first quarter of 2010 compared to the first quarter of 2009. Effective April 4, 2009, SCE's overall system average rate increased due to the implementation of both revenue allocation and rate design changes authorized in the 2009 GRC and the FERC transmission rate changes authorized in the 2009 FERC rate case. The sales volume decrease was due to the economic downturn. 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.

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 $296 million and $505 million for the three months ended March 31, 2010 and 2009, respectively. Effective January 1, 2010, the CDWR-related rates were decreased primarily to refund CDWR overcollections to customers.

Effective Income Tax Rates

SCE's effective tax rates were 42% and 35% (excluding income attributable to noncontrolling interests) for the three months ended March 31, 2010 and 2009, respectively. The increase in the effective tax rate was primarily due to a $39 million non-cash charge recorded in the first quarter of 2010 to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010, partially offset by higher property-related flow-through tax deductions in 2010.

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.

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Available Liquidity

As of March 31, 2010, SCE had approximately $2.7 billion of available liquidity comprised of cash and equivalents and short-term investments and $2.6 billion available under credit facilities. As of March 31, 2010, SCE's long-term debt, including current maturities of long-term debt, was $7.0 billion.

The following table summarizes the status of SCE's credit facilities at March 31, 2010:

(in millions)	Credit Facilities ¹


Commitment	$	2,894
Outstanding borrowings		(180	)
Outstanding letters of credit		(82	)

Amount available	$	2,632

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 March 31, 2010, SCE's debt to total capitalization ratio was 0.46 to 1.

Regulatory Proceedings

Energy Efficiency Risk/Reward Incentive Mechanism

As discussed in the year-ended 2009 MD&A, the CPUC adopted an Energy Efficiency Risk/Reward Incentive Mechanism applicable to the 2006 – 2008 performance period under which SCE expected to receive a $27 million final payment in late 2010. Settlement negotiations on the 2006 – 2008 energy savings and earnings are expected to begin in late May 2010 and 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

Dividend Restrictions

The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted-average basis. At March 31, 2010, SCE's 13-month

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weighted-average common equity component of total capitalization was 50.5% resulting in the capacity to pay $381 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)	March 31, 2010


Collateral posted as of March 31, 2010 ¹	$	97
Incremental collateral requirements resulting from a potential downgrade of SCE's credit rating to below investment grade		154

Total posted and potential collateral requirements ²	$	251

¹: Collateral posted consisted of $10 million which was offset against net derivative liabilities and $87 million provided to counterparties and other brokers (consisting of $5 million in cash reflected in "Margin and collateral deposits" on the consolidated balance sheets and $82 million in letters of credit).
²: Total posted and potential collateral requirements may increase by an additional $32 million, based on SCE's forward position as of March 31, 2010, due to adverse market price movements over the remaining life of the existing contracts using a 95% confidence level.

In the table above, there was zero collateral posted as of March 31, 2010 related to derivative liabilities, and $16 million of incremental collateral requirements related to derivative liabilities.

Historical Consolidated Cash Flow

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

Condensed Consolidated Statement of Cash Flows

	Three Months Ended March 31,

(in millions)	2010			2009

Cash flows provided by operating activities	$	313		$	406
Cash flows provided (used) by financing activities		305			(101	)
Cash flows used by investing activities		(922	)		(739	)
Effect of deconsolidation of variable interest entities		(92	)		—

Net decrease in cash and equivalents	$	(396	)	$	(434	)

Cash Flows Provided by Operating Activities

Cash provided by operating activities decreased $93 million in the first quarter of 2010, compared to the first quarter of 2009 primarily due to a decrease in pre-tax income, the timing of cash receipts and

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disbursements related to working capital items and income taxes paid in 2010 compared to income tax refunds received in 2009.

Cash Flows Provided (Used) by Financing Activities

Cash provided (used) by financing activities mainly consisted of net repayments of short-term debt and long-term debt issuances (payments).

Cash provided by financing activities for the first quarter of 2010 were $305 million consisting of the following significant events:

•: Issued $500 million of first refunding mortgage bonds due in 2040. The bond proceeds were used to repay commercial paper borrowings and for general corporate purposes.
•: Borrowed $180 million under SCE's line of credit to fund interim working capital requirements.
•: Repaid $250 million of senior unsecured notes.
•: Paid $100 million in dividends to Edison International.

Cash used by financing activities for the first quarter of 2009 were $101 million consisting of the following significant events:

•: 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 $335 million borrowings under SCE's line of credit, primarily due to the improvement in economic conditions that occurred during the second half of 2008.
•: Repaid $150 million of first and refunding mortgage bonds.
•: Purchased $219 million of two issues of tax-exempt pollution control bonds and converted the issues to a variable rate structure. SCE continues to hold the bonds which remain 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 were $867 million and $690 million for the three months ended March 31, 2010 and 2009, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $49 million and $42 million for the three months ended March 31, 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."

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Contingencies

Developments related to SCE's FERC Transmission Incentives and CWIP Proceedings and its Navajo Nation Litigation are discussed in "SCE Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies."

Environmental Remediation

As of March 31, 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. See "SCE Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies" for further discussion.

MARKET RISK EXPOSURES

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

Interest Rate Risk

At March 31, 2010, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $7.4 billion, compared to a carrying value of $7.0 billion.

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."

	March 31, 2010						December 31, 2009


(in millions)	Assets			Liabilities			Assets		Liabilities

Electricity options, swaps and forward arrangements	$	—		$	82		$	1	$	25
Natural gas options, swaps and forward arrangements		74			296			86		171
Congestion revenue rights		199			—			217		—
Tolling arrangements ¹		—			732			43		402
Netting and collateral		(2	)		(12	)		—		—

Total	$	271		$	1,098		$	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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(in millions)

Fair value of derivative contracts, net liability at January 1, 2010		$	(251	)
Total realized/unrealized net losses:
	Included in regulatory assets and liabilities ¹		(605	)
Purchases and settlements, net			19
Netting and collateral			10

Fair value of derivative contracts, net liability at March 31, 2010		$	(827	)

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 from ratepayers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are deferred and are not recognized as purchased power expense, and therefore do not affect earnings. Realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than average fixed prices. Unrealized gains on economic hedging activities were primarily due to the decrease in forward natural gas prices and declining market conditions related to SCE's new generation contracts.

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 balance sheet. 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 March 31, 2010, the amount of balance sheet exposure as described above, broken down by the credit ratings of SCE's counterparties, was as follows:

	March 31, 2010

(in millions)	Exposure ²		Collateral		Net Exposure

S&P Credit Rating ¹
A or higher	$	209	$	—	$	209
A-		1		—		1
BBB+		—		—		—
BBB		—		—		—
BBB-		—		—		—
Below investment grade and not rated		—		—		—

Total	$	210	$	—	$	210

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 sheet, except for any related net accounts receivable.

The credit risk exposure set forth in the above table is comprised of $1 million of net account receivables and $209 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

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The CAISO comprises 95% 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."

ITEM 6. EXHIBITS


	10.1		Credit Agreement dated as of March 5, 2010 among Southern California Edison Company and Bank of America, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and Barclays Bank PLC, Morgan Stanley Bank, N.A., SunTrust Bank, UBS Loan Finance LLC, US Bank, National Association, BNP Paribas, Royal Bank of Canada, and The Bank of Nova Scotia as Co-Documentation Agents, and the lenders thereto. (File No. 1-2313, filed as Exhibit 10 to Southern California Edison Company form 8-K dated March 5, 2010)*
	10.2		Edison International 2010 Executive Annual Incentive Program (File No. 1-9936, filed as Exhibit 10.1 to the Edison International's Form 10-Q for the quarter ended March 31, 2010)*

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	10.3		Edison International 2010 Long-Term Incentives Terms and Conditions (File No. 1-9936 filed as Exhibit 10.2 to Edison International Form 10-Q for the quarter ended March 31, 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 March 31, 2010, filed on May 7, 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 tagged as blocks of text.

*: 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: May 7, 2010

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Part I Financial Information Item 1. Financial Statements Note 1. Summary Of Significant Accounting Policies Note 2. Derivative Instruments and Hedging Activities Note 3. Liabilities and Lines Of Credit Note 4. Income Taxes Note 5. Compensation and Benefit Plans Note 6. Commitments and Contingencies Note 7. Consolidated Statement Of Changes in Equity Note 8. Supplemental Cash Flows Information Note 9. Fair Value Measurements Note 10. Regulatory Assets and Liabilities Note 11. Other Income and Expenses Note 12. Variable Interest Entities Item 2. Management's Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4T. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 6. Exhibits

SCE 10-Q Quarter ended March 31, 2010