SOUTHERN CALIFORNIA EDISON (SCE-PN) 10-Q 2009 Q3 Quarterly report

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

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2009
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 (§232.405 of this chapter) 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, or non-accelerated filer.

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 November 3, 2009
Common Stock, no par value	434,888,104

SOUTHERN CALIFORNIA EDISON

INDEX

				Page
PART I. FINANCIAL INFORMATION				1
	Item 1.	Financial Statements		1
		Consolidated Statements of Income – Three and Nine Months Ended September 30, 2009 and 2008		1
		Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2009 and 2008		1
		Consolidated Balance Sheets – September 30, 2009 and December 31, 2008		2
		Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2009 and 2008		4
		Notes to the Consolidated Financial Statements		5
		Management's Statement		5
		Note 1. Summary of Significant Accounting Policies		5
		Note 2. Derivative Instruments and Hedging Activities		9
		Note 3. Liabilities and Lines of Credit		11
		Note 4. Income Taxes		12
		Note 5. Compensation and Benefits Plans		13
		Note 6. Commitments and Contingencies		16
		Note 7. Consolidated Statement of Changes in Equity		22
		Note 8. Property and Plant		23
		Note 9. Supplemental Cash Flows Information		24
		Note 10. Fair Value Measurements		24
		Note 11. Regulatory Assets and Liabilities		29
		Note 12. Variable Interest Entities		30
		Note 13. Business Segments		31
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		34
		Management Overview		36
			Areas of Business Focus	36
			Global Settlement	38
			Earnings Performance	39
		Regulatory Matters		39
			Current Regulatory Developments	39
		Other Developments		40
			Environmental Matters	40
			Wildfire Insurance Issues	43

				Page
		Liquidity		43
			Overview	43
			American Recovery and Reinvestment Act of 2009	44
			Repair Deductions	44
			Intercompany Tax-Allocation Agreement	45
			Capital Expenditures	45
			Credit Ratings	46
			Dividend Restrictions and Debt Covenants	46
			Margin and Collateral Deposits	46
		Market Risk Exposures		47
			Commodity Price Risk	47
			Interest Rate Risk	49
			Credit Risk	49
		Results of Operations		50
		Historical Cash Flow Analysis		54
		New Accounting Requirements		56
		Commitments and Indemnities		56
			Uncertain Tax Position Net Liability	56
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		56
	Item 4.	Controls and Procedures		56
			Disclosure Controls and Procedures	56
			Internal Control Over Financial Reporting	56
PART II. OTHER INFORMATION				57
	Item 6.	Exhibits		57
SIGNATURE				58

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	Clean 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	United States 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
FTRs	firm transmission rights
GAAP	generally accepted accounting principles
GHG	greenhouse gas
Global Settlement	A settlement between Edison International and the IRS that resolves all outstanding tax disputes for open tax years 1986 through 2002.
GRC	General Rate Case
Investor-Owned Utilities	SCE, SDG&E and PG&E
IRS	Internal Revenue Service
ISO	Independent System Operator
kWh(s)	kilowatt-hour(s)

GLOSSARY (Continued)

MD&A	Management's Discussion and Analysis of Financial Condition and Results of Operations
Mohave	Mohave Generating Station
MRTU	Market Redesign and Technology Upgrade
MW	megawatts
MWh	megawatt-hours
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NOx	nitrogen oxide
NRC	Nuclear Regulatory Commission
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
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
SO2	sulfur dioxide
SRP	Salt River Project Agricultural Improvement and Power District
The Tribes	Navajo Nation and Hopi Tribe
TURN	The Utility Reform Network
US EPA	United States Environmental Protection Agency
VIE(s)	variable interest entity(ies)

SOUTHERN CALIFORNIA EDISON

PART I. FINANCIAL INFORMATION

Item 1.    Financial Statements

CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2009			2008			2009			2008
	(Unaudited)
Operating revenue	$	3,069		$	3,468		$	7,531		$	8,698
Fuel		177			415			533			1,161
Purchased power		1,032			1,333			2,155			3,053
Other operation and maintenance		802			721			2,222			2,145
Depreciation, decommissioning and amortization		302			276			877			830
Property and other taxes		60			61			187			179
Gain on sale of assets		—			(1	)		(1	)		(9	)
Total operating expenses		2,373			2,805			5,973			7,359
Operating income		696			663			1,558			1,339
Interest income		4			2			9			12
Other nonoperating income		69			20			126			69
Interest expense – net of amounts capitalized		(105	)		(104	)		(320	)		(297	)
Other nonoperating deductions		(13	)		(81	)		(33	)		(114	)
Income before income taxes		651			500			1,340			1,009
Income tax expense		236			158			159			268
Net income		415			342			1,181			741
Less: Net income attributable to noncontrolling interests		56			94			90			161
Dividends on preferred and preference stock not subject to mandatory redemption		13			13			38			38
Net income available for common stock	$	346		$	235		$	1,053		$	542

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

			Three Months Ended September 30,					Nine Months Ended September 30,
In millions			2009		2008			2009		2008
			(Unaudited)
Net income			$	415	$	342		$	1,181	$	741
Other comprehensive income (loss), net of tax:
	Pension and postretirement benefits other than pensions:
		Amortization of net gain (loss) included in net income – net		—		(1	)		1		(2	)
Comprehensive income				415		341			1,182		739
Less: Comprehensive income attributable to noncontrolling interests				56		94			90		161
Comprehensive income attributable to SCE			$	359	$	247		$	1,092	$	578

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

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SOUTHERN CALIFORNIA EDISON

CONSOLIDATED BALANCE SHEETS

In millions		September 30, 2009			December 31, 2008
		(Unaudited)
ASSETS
Cash and equivalents		$	754		$	1,611
Short-term investments			3			3
Receivables, less allowances of $47 and $39 for uncollectible accounts at respective dates			952			703
Accrued unbilled revenue			583			328
Inventory			332			365
Derivative assets			195			157
Regulatory assets			57			605
Deferred income taxes – net			16			147
Other current assets			127			283
Total current assets			3,019			4,202
Nonutility property – less accumulated depreciation of $733 and $765 at respective dates			330			953
Nuclear decommissioning trusts			3,025			2,524
Other investments			80			68
Total investments and other assets			3,435			3,545
Utility plant, at original cost:
	Transmission and distribution		21,035			20,006
	Generation		2,633			1,819
Accumulated depreciation			(5,757	)		(5,570	)
Construction work in progress			2,688			2,454
Nuclear fuel, at amortized cost			277			260
Total utility plant			20,876			18,969
Derivative assets			237			74
Regulatory assets			5,084			5,414
Other long-term assets			503			364
Total long-term assets			5,824			5,852
Total assets		$	33,154		$	32,568

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

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SOUTHERN CALIFORNIA EDISON

CONSOLIDATED BALANCE SHEETS

In millions, except share amounts	September 30, 2009			December 31, 2008
	(Unaudited)
LIABILITIES AND EQUITY
Short-term debt	$	—		$	1,893
Current portion of long-term debt		250			150
Accounts payable		888			948
Accrued taxes		239			340
Accrued interest		100			153
Customer deposits		241			227
Book overdrafts		259			224
Derivative liabilities		104			156
Regulatory liabilities		1,176			1,111
Other current liabilities		608			572
Total current liabilities		3,865			5,774
Long-term debt		6,490			6,212
Deferred income taxes – net		3,335			2,918
Deferred investment tax credits		99			101
Customer advances		123			137
Derivative liabilities		632			738
Pensions and benefits		2,613			2,485
Asset retirement obligations		3,137			3,007
Regulatory liabilities		2,848			2,481
Other deferred credits and other long-term liabilities		1,338			902
Total deferred credits and other liabilities		14,125			12,769
Total liabilities		24,480			24,755
Commitments and contingencies (Note 6)
Common stock, no par value (434,888,104 shares outstanding at each date)		2,168			2,168
Additional paid-in capital		548			532
Accumulated other comprehensive loss		(13	)		(14	)
Retained earnings		4,675			3,827
Total common shareholder's equity		7,378			6,513
Preferred and preference stock not subject to mandatory redemption		920			920
Noncontrolling interests		376			380
Total equity		8,674			7,813
Total liabilities and equity	$	33,154		$	32,568

Authorized common stock is 560 million shares at each reporting period.

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

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SOUTHERN CALIFORNIA EDISON

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Nine Months Ended September 30,
In millions		2009			2008
		(Unaudited)
Cash flows from operating activities:
Net income		$	1,181		$	741
Adjustments to reconcile to net cash provided by operating activities:
	Depreciation, decommissioning and amortization		877			830
	Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)		133			42
	Other amortization		88			73
	Stock-based compensation		10			13
	Deferred income taxes and investment tax credits		353			(22	)
	Long-term regulatory assets and liabilities – net		338			(28	)
	Long-term derivative assets and liabilities – net		(269	)		32
	Other assets		(147	)		(39	)
	Other liabilities		469			(22	)
Changes in working capital:
	Receivables and accrued unbilled revenue		(498	)		(453	)
	Inventory		33			(61	)
	Other current assets		170			95
	Book overdrafts		35			94
	Accrued taxes		(101	)		87
	Accounts payable and other current liabilities		86			65
	Current regulatory assets and liabilities – net		613			(97	)
	Current derivative assets and liabilities – net		(90	)		(37	)
Net cash provided by operating activities			3,281			1,313
Cash flows from financing activities:
Long-term debt issued			750			1,000
Long-term debt issuance costs			(11	)		(14	)
Long-term debt repaid			(153	)		(3	)
Bonds repurchased			(219	)		(212	)
Preferred stock redeemed			—			(7	)
Short-term debt financing – net			(1,893	)		1,058
Stock-based compensation – net			4			(10	)
Distributions to noncontrolling interests			(94	)		(156	)
Dividends paid			(238	)		(263	)
Net cash provided (used) by financing activities			(1,854	)		1,393
Cash flows from investing activities:
Capital expenditures			(2,109	)		(1,638	)
Proceeds from nuclear decommissioning trust sales			1,814			2,279
Purchases of nuclear decommissioning trust investments and other			(1,977	)		(2,329	)
Sales of short-term investments			1			—
Purchases of short-term investments			(1	)		(3	)
Customer advances for construction and other investments			(12	)		(11	)
Net cash used by investing activities			(2,284	)		(1,702	)
Net increase (decrease) in cash and equivalents			(857	)		1,004
Cash and equivalents, beginning of period			1,611			252
Cash and equivalents, end of period		$	754		$	1,256

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

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SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Management's Statement

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary for a fair statement of the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and nine-month periods ended September 30, 2009 are not necessarily indicative of the operating results for the full year.

This quarterly report should be read in conjunction with SCE's Annual Report to Shareholders incorporated by reference into SCE's Annual Report on Form 10-K for the year ended December 31, 2008 and Current Report on Form 8-K filed with the Securities and Exchange Commission on March 2, 2009 and August 14, 2009, respectively.

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

SCE's significant accounting policies were described in Note 1 of "Notes to consolidated financial statements" included in its 2008 Annual Report on Form 10-K. SCE follows the same accounting policies for interim reporting purposes.

The December 31, 2008 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.

Certain prior-period reclassifications have been made to conform to the current year financial statement presentation mostly pertaining to the presentation of noncontrolling interest in the consolidated financial statements and the elimination of the previously reported income statement caption "Provision for regulatory adjustment clauses – net" through classifications within relevant captions including "Operating revenue," "Purchased power," "Other operation and maintenance" and "Depreciation, decommissioning and amortization."

SCE has performed an evaluation of subsequent events through November 6, 2009, the date the financial statements were issued.

Cash Equivalents

Cash equivalents included money market funds totaling $647 million and $1.53 billion at September 30, 2009 and December 31, 2008, 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 10. Included in cash and equivalents is $94 million and $89 million at September 30, 2009 and December 31, 2008, respectively for four projects that SCE is consolidating under an accounting interpretation for VIEs.

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers (reflected in "Other current assets" on the consolidated balance sheets) and cash received from counterparties (reflected in "Other current liabilities" on the consolidated balance sheets) as credit support under

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energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the positions. In accordance with the authoritative guidance which allows for netting of counterparty receivables and payables under a master netting arrangement, SCE presents a portion of its margin and cash collateral deposits net with its derivative positions on its consolidated balance sheets. Amounts recognized for cash collateral provided to others that have been offset against derivative liabilities totaled $1 million and $72 million at September 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral provided to others that have not been offset against derivative liabilities totaled $16 million and $17 million at September 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral received from others that have not been offset against derivative assets totaled $26 million and $8 million at September 30, 2009 and December 31, 2008, respectively.

New Accounting Requirements

Accounting Requirements Adopted

General Principles

In June 2009, the FASB issued an accounting standard establishing the FASB Accounting Standards Codification (Codification) as the source of authoritative, nongovernmental U.S. GAAP superseding existing FASB, American Institute of Certified Public Accountants (AICPA), Emerging Issues Task Force (EITF) and related literature. Following this action, the FASB will not issue new standards in the form of Statements, FASB Staff Positions or EITF Abstracts. Instead, the FASB will issue Accounting Standards Updates. Two levels of U.S. GAAP will exist: authoritative and non-authoritative. Codification is not intended to change U.S. GAAP or guidance issued by the SEC. SCE adopted the Codification effective July 1, 2009.

Subsequent Events

In May 2009, the FASB issued authoritative guidance that sets forth the period subsequent to the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity should recognize these events or transactions; and the disclosures that an entity should make. SCE adopted this guidance effective April 1, 2009. The adoption had no impact on SCE's consolidated results of operations, financial position or cash flows.

Fair Value Measurements and Disclosures

In April 2009, the FASB issued authoritative guidance affirming the objective of a fair value measurement, which is to identify the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction at the measurement date between market participants ("exit price") under current market conditions. This includes guidance on identifying circumstances that indicate when there is no active market or transactions where the price inputs being used represent distressed or forced sales. If either of these conditions exists, this guidance provides additional direction for estimating fair value and requires disclosure of a change in valuation technique (and the related inputs) resulting from the application of this guidance and to quantify its effects, if practicable. This guidance also requires disclosures on a more disaggregated basis for investments in debt and equity securities measured at fair value. SCE adopted this guidance effective April 1, 2009. The adoption had no impact on SCE's consolidated results of operations, financial position or cash flows. See Note 10.

In April 2009, the FASB issued authoritative guidance requiring disclosures about the fair value of all financial instruments, for which it is practicable to estimate that fair value, for interim reporting periods as well as annual statements. SCE adopted this guidance effective April 1, 2009. Since this guidance

6

impacts disclosure only, the adoption did not have an impact on SCE's consolidated results of operations, financial position or cash flows. See Note 10.

Effective January 1, 2009, SCE adopted authoritative guidance for nonrecurring fair value measurements of nonfinancial assets and liabilities. The adoption did not have a material impact on SCE's consolidated financial statements.

Investments-Debt and Equity Securities

In April 2009, the FASB amended existing authoritative guidance which determines whether impairment is other than temporary for debt securities. Under this amended guidance, an entity writes down to fair value through earnings, impaired debt securities that it currently intends to sell or for which it is more likely than not it will be required to sell before the anticipated recovery. If an entity does not intend and will not be required to sell a debt security but it is probable that the entity will not collect all amounts due, the entity will separate the other-than-temporary impairment into two components: 1) the amount due to credit loss would be recognized in earnings, and 2) the remaining portion would be recognized in other comprehensive income. SCE adopted this guidance, effective April 1, 2009 resulting in increased disclosures. The adoption did not have an impact on SCE's consolidated results of operations, financial position or cash flows. See Note 10.

Consolidation

In December 2007, the FASB issued authoritative guidance, requiring an entity to present noncontrolling interests that reflect the ownership interests in subsidiaries held by parties other than the entity, within the equity section but separate from the entity's equity in the consolidated financial statements. It also requires the amount of consolidated net income attributable to the parent and to the noncontrolling interests to be clearly identified and presented on the face of the consolidated statements of income; changes in ownership interests to be accounted for similarly as equity transactions; and when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary to be measured at fair value. SCE adopted this guidance effective January 1, 2009 and retrospectively applied this guidance as of December 31, 2008. In accordance with this guidance, SCE reclassified "Noncontrolling interests – other" of $380 million and "Preferred and preference stock of utility not subject to mandatory redemption" of $920 million to a component of equity. For additional information, see Note 7.

Derivatives and Hedging

In March 2008, the FASB issued authoritative guidance, requiring additional disclosures related to derivative instruments, including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SCE adopted this guidance effective January 1, 2009. Since this guidance impacts disclosures only, the adoption did not have an impact on SCE's consolidated results of operations, financial position or cash flows. For additional information regarding the adoption, see Note 2.

Accounting Requirements Not Yet Adopted

Compensation-Retirement Benefits

In December 2008, the FASB issued authoritative guidance requiring additional postretirement benefit plan asset disclosures by employers about the major categories of assets, the inputs and valuation techniques used to measure fair value, the level within the fair value hierarchy, the effect of using

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significant unobservable inputs (Level 3) and significant concentrations of risk. This guidance is effective for years ending after December 15, 2009 and, therefore, SCE will adopt this guidance at year-end 2009. This guidance will impact disclosures only and will not have an impact on SCE's consolidated results of operations, financial position or cash flows.

Consolidation-Variable Interest Entities

In June 2009, the FASB issued an amendment on the accounting and disclosure requirements for the consolidation of variable interest entities. This amendment 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 entity's purpose and design and a company's ability to direct the activities of the entity that most significantly impact the entity's economic performance. SCE is currently evaluating the impact that the adoption will have on its consolidated financial statements including the impact on four QF contracts in which SCE has variable interests and currently consolidates. SCE will adopt this guidance on January 1, 2010.

Fair Value Measurements

In August 2009, the FASB issued an accounting standards update that provides additional guidance on how companies should measure liabilities at fair value. While reaffirming the existing definition of fair value, the update reintroduced the concept of entry value into the determination of fair value. Entry value is the amount an entity would receive to enter into an identical liability. Under the new guidance, the fair value of a liability is not adjusted to reflect the impact of contractual restrictions that prevent its transfer. If the quoted price of a liability when traded as an asset includes the effect of a credit enhancement (i.e. a guarantee), this effect should be excluded from the measurement of the liability. SCE adopted this guidance effective October 1, 2009. This guidance is not expected to have a material impact on its consolidated financial statements.

In September 2009, the FASB issued an accounting standards update that provides additional guidance on how companies should measure the fair value of certain alternative investments such as hedge funds, private equity funds, venture capital funds and funds of funds. This update is designed to address concerns regarding how to appropriately adjust the Net Asset Value (NAV) of these investments to reflect specific attributes, including redemption restrictions and capital commitments. If the investee's underlying investments are measured at fair value at the investor's measurement date, this update allows investors to use NAV to estimate the fair value unless it is probable the investment will be sold at something other than NAV. If not calculated as of the reporting entity's measurement date, the NAV must be adjusted for significant market events. This update provides guidance on fair value hierarchy classification and also requires enhanced disclosures. SCE is currently evaluating the impact, if any, that the adoption will have on certain investments in the defined benefit pension and PBOP plans and the resulting impact on the funded status of these plans recorded on SCE's balance sheets. SCE will adopt this guidance on December 31, 2009.

Related Party Transactions

During the first quarter of 2008, a subsidiary of EME was awarded, through a competitive bidding process, a ten-year power sales contract with SCE for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. Deliveries under the power sales agreement are expected to commence in 2013. The project is subject to resolution of uncertainty regarding the availability of required emission credits.

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Note 2. Derivative Instruments and Hedging Activities

Commodity Price Risk

SCE is exposed to commodity price risk from its purchases of capacity and ancillary services to meet peak energy requirements and from exposure to natural gas prices that affect costs associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including the Mountainview and peaker plants. Contract energy prices for most nonrenewable QFs are based in large part on the monthly index price of natural gas delivered at the Southern California border. SCE also has power contracts, referred to as tolling arrangements, in which SCE has agreed to provide the natural gas needed for generation under those power contracts or pay for the natural gas based on published index prices. In addition to the Mountainview and peaker plants, approximately 42% of SCE's purchased power supply is subject to natural gas price volatility. Fair value changes in SCE's derivative instruments are expected to be recovered from or refunded to ratepayers and therefore, fair value changes have no impact on earnings, but may temporarily affect cash flows.

Natural Gas and Electricity Price Risk

SCE has an active hedging program in place to minimize ratepayer exposure to variability in market prices; however, to the extent that SCE does not mitigate the exposure to commodity price risk, the unhedged portion is subject to the risks and benefits of spot-market price movements, which are ultimately passed-through to ratepayers.

To mitigate SCE's exposure to variability in market prices, SCE enters into energy options, tolling arrangements, forward physical contracts and transmission congestion revenue rights (CRRs). SCE also enters into contracts for power and gas options, as well as swaps and futures, in order to mitigate its exposure to increases in natural gas and electricity pricing. These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans.

SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale. The derivative instrument fair values are marked to market at the end of each reporting period. Any fair value changes are expected to be recovered from or refunded to customers through regulatory mechanisms and therefore, SCE's fair value changes have no impact on purchased-power expense or earnings. Hedge accounting is not used for these transactions due to this regulatory accounting treatment.

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Notional Volumes of Derivative Instruments

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

Commodity	Unit of Measure	Economic Hedges
		(Unaudited)
Electricity options, swaps and forward arrangements	MW		24,308
Natural gas options, swaps and forward arrangements	Bcf		272
Congestion revenue rights(1)	MW		516,488
Tolling arrangements(2)	MW		2,556

(1)

In September 2007 and November 2008, the CAISO allocated CRRs for the period April 2009 through December 2017 based on SCE's load requirements. In addition, SCE participated in CAISO auctions for the procurement of additional CRRs. These CRRs meet the definition of a derivative.

(2)

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, of which five received regulatory approval in the fourth quarter of 2008 and 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 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.

Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at September 30, 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	$	203		$	237	$	440		$	113		$	632	$	745		$	305
Netting and collateral			(8	)		—		(8	)		(9	)		—		(9	)		(1	)
Total		$	195		$	237	$	432		$	104		$	632	$	736		$	304

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. Due to expected future recovery from ratepayers, unrealized gains and losses are deferred and are not recognized as purchased-power expense until realized. As a result, realized and unrealized gains and losses do not affect earnings, but may temporarily affect cash flows. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows. Realized losses on economic hedging activities were $113 million and $307 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to realized gains on economic hedging activities of $14 million and $39 million for the comparable periods in 2008, respectively. Unrealized losses on economic hedging activities were $198 million for the three months ended September 30, 2009, and

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unrealized gains on economic hedging activities were $428 million for the nine months ended September 30, 2009. Unrealized losses on economic hedging activities were $617 million and $131 million for the comparable periods in 2008, respectively.

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 as of September 30, 2009, was $74 million, for which SCE has posted no collateral to its counterparties. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2009, SCE would be required to post an additional $18 million of collateral.

Note 3. Liabilities and Lines of Credit

Long-Term Debt

In March 2009, SCE issued $500 million of 6.05% and $250 million of 4.15% first and refunding mortgage bonds due in 2039 and 2014, respectively. The bond proceeds were used for general corporate purposes and to finance fuel inventories.

In February 2009, SCE repaid $150 million of its first and refunding mortgage bonds. In March 2009, SCE purchased two issues of its tax-exempt pollution control bonds totaling $219 million 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.

Credit Agreements

On March 17, 2009, SCE entered into a new $500 million 364-day revolving credit facility, terminating on March 16, 2010. The additional liquidity provided by the facility will be used to support SCE's ongoing power procurement-related needs.

In June 2009, SCE amended its $2.5 billion five-year credit facility to remove a subsidiary of Lehman Brothers Holdings as a lender which resulted in a reduction of the total commitment under the facility to $2.4 billion.

The following table summarizes the status of the SCE credit facilities at September 30, 2009:

In millions	(Unaudited)
Commitment	$	2,894
Outstanding borrowings		—
Outstanding letters of credit		(82	)
Amount available	$	2,812

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Note 4. Income Taxes

SCE's composite federal and state statutory income tax rates were approximately 41% and 40% (net of the federal benefit for state income taxes) for 2009 and 2008 respectively. SCE's effective tax rates, excluding income attributable to non-controlling interests, were 40% and 13% for the three- and nine-month periods ended September 30, 2009, respectively, as compared to 39% and 32% for the respective periods in 2008. The principal items affecting comparability of the effective tax rates for the three- and nine-month periods ended September 30, 2009 and 2008 were lower software and property flow-through deductions in 2009, partially offset by higher nondeductible expenses during 2008. The nine-month period also includes a $300 million benefit recorded in 2009 related to the Global Settlement discussed below.

The American Recovery and Reinvestment Act of 2009 (ARRA) included a number of provisions that provide tax incentives to stimulate the economy, including incentives for energy-related investments and activities. ARRA extended the 50% bonus depreciation provision for an additional year to include property placed in service by December 31, 2009 and provides for an option to elect a cash grant in lieu of an investment tax credit for certain renewable energy property including solar energy. To elect the cash grant, an application must be filed with the United States Department of Treasury. SCE's PV Solar Rooftop facilities are expected to qualify for the investment tax credit and SCE also expects that it will have the option to elect the cash grant. SCE is reviewing rules issued by the United States Department of Treasury regarding the grant program in conjunction with its evaluation as to whether to make the grant election. SCE accounts for investment tax credits on the deferred method and, accordingly, will recognize tax benefits related to such credits over the estimated useful life of the projects.

Accounting for Uncertainty in Income Taxes

The following table provides a reconciliation of unrecognized tax benefits from January 1 to September 30 for 2009 and 2008:

In millions			2009			2008
			(Unaudited)
Balance at January 1			$	2,066		$	1,950
	Tax positions taken during the current year
		Increases		48			72
	Tax positions taken during a prior year
		Increases		155			106
		Decreases		(30	)		(129	)
	Decreases for settlements during the period			(1,741	)		—
Balance at September 30			$	498		$	1,999

Unrecognized tax benefits were reduced by $1.7 billion during the second quarter of 2009 as a result of consummating the Global Settlement discussed below.

SCE believes it is reasonably possible that unrecognized tax benefits could be reduced by up to $70 million within the next twelve months from settlement of state tax matters for periods through 2002.

As of September 30, 2009 and December 31, 2008, respectively, if recognized, $82 million and $60 million of the unrecognized tax benefits would impact the effective tax rate.

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Accrued Interest and Penalties

The total amount of accrued interest and penalty related to SCE's income tax reserve was $70 million and $120 million as of September 30, 2009 and December 31, 2008, respectively. After-tax interest income, recognized in income tax expense, was $284 million for the nine months ended September 30, 2009. After-tax interest expense, recognized in income tax expense, was $5 million for the three months ended September 30, 2009 and was $3 million and $12 million for the three- and nine-month periods ended September 30, 2008, respectively.

Tax Years Subject to Examination

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 years 2008. Consummation of the Global Settlement, as described below, effectively closed tax years 1986 - 2002 with the IRS.

Edison International's California and other state income tax returns are open for examination by the California Franchise Tax Board and other state tax authorities for tax years 1986 through 2008. The Franchise Tax Board is currently examining tax years through 2002.

Global Settlement

As previously disclosed, Edison International and the IRS finalized the terms of a Global Settlement on May 5, 2009. The Global Settlement resolves all of SCE's federal income tax disputes and affirmative claims through tax year 2002. During the second quarter of 2009, SCE recorded after-tax earnings of approximately $300 million, reflected in "Income tax expense" on the consolidated statements of income, primarily related to settlement of two affirmative claims associated with: (1) the taxation of balancing account overcollections; and (2) taxation of proceeds received in consideration for transferring control of SCE's transmission system to the CAISO and allowing direct access to SCE's distribution system, which were mandated as part of California's deregulation process. Both claims created tax timing differences that resulted in an interest refund from the IRS for prior period tax overpayments, but did not result in a permanent reduction in Edison International's and SCE's federal income tax liability. SCE expects an overall positive cash impact resulting from the Global Settlement of approximately $640 million over time, including the cash benefit of prior tax deposits of approximately $200 million.

Edison International is addressing the impacts of the Global Settlement with state tax authorities and is awaiting final interest calculations from the IRS. Resolution of such matters with such authorities may change the estimated cash and earnings impacts described above.

Note 5. Compensation and Benefits Plans

Pension Plans

For the nine months ended September 30, 2009, SCE made 2009 plan year contributions of $50 million and expects to make $47 million of additional contributions in the last three months of 2009. SCE's total 2009 annual contributions are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to its total annual expense.

Net pension cost recognized is calculated under the actuarial method used for ratemaking. The difference between pension costs calculated for accounting and ratemaking is deferred.

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Expense components are:

	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2009			2008			2009			2008
	(Unaudited)
Service cost	$	27		$	27		$	81		$	81
Interest cost		48			46			144			138
Expected return on plan assets		(40	)		(63	)		(120	)		(189	)
Amortization of prior service cost		4			4			12			13
Amortization of net (gain)/loss		13			—			39			(1	)
Subtotal	$	52		$	14		$	156		$	42
Regulatory adjustment – deferred		(24	)		—			(72	)		—
Total expense recognized	$	28		$	14		$	84		$	42

Postretirement Benefits Other Than Pensions

For the nine months ended September 30, 2009, SCE made 2009 plan year contributions of $13 million and expects to make $67 million of additional contributions in the last three months of 2009. SCE's total 2009 annual contributions are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to its total annual expense.

Expense components are:

	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2009			2008			2009			2008
	(Unaudited)
Service cost	$	7		$	11		$	21		$	33
Interest cost		29			33			88			99
Expected return on plan assets		(20	)		(31	)		(60	)		(93	)
Amortization of prior service credit		(7	)		(7	)		(21	)		(21	)
Amortization of net loss		11			4			32			12
Total expense recognized	$	20		$	10		$	60		$	30

Stock-Based Compensation

During the first quarter of 2009, Edison International granted its 2009 stock-based compensation awards, which included stock options, performance shares, deferred stock units and restricted stock units. Total stock-based compensation expense (reflected in the caption "Other operation and maintenance" on the consolidated statements of income) was $6 million and $2 million for the three months ended September 30, 2009 and 2008, respectively, and was $15 million and $11 million for the nine months ended September 30, 2009 and 2008, respectively. The income tax benefit recognized in the consolidated statements of income was $2 million and $1 million for the three months ended September 30, 2009 and 2008, respectively and was $6 million and $5 million for the nine months ended September 30, 2009 and 2008, respectively. Total stock-based compensation cost capitalized was $1 million and $2 million for the three- and nine-month periods ended September 30, 2008. Consistent with SCE's 2009 GRC, no stock-based compensation was capitalized in 2009.

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Stock Options

A summary of the status of Edison International stock options issued at SCE is as follows:

				Weighted-Average
	Stock Options			Exercise Price		Remaining Contractual Term (Years)		Aggregate Intrinsic Value
	(Unaudited)
Outstanding at December 31, 2008		6,400,734		$	34.58
Granted		2,857,975		$	25.15
Expired		(23,594	)	$	38.69
Forfeited		(155,792	)	$	32.11
Exercised		(189,148	)	$	21.41
Affiliate transfers – net		(86,269	)	$	34.92
Outstanding at September 30, 2009		8,803,906		$	31.88		6.76
Vested and expected to vest at September 30, 2009		8,398,104		$	31.83		6.67	$	35,357,145
Exercisable at September 30, 2009		4,625,277		$	30.78		5.01	$	22,642,260

The amount of cash used to settle stock options exercised was $2 million and $3 million for the three months ended September 30, 2009 and 2008, respectively, and was $6 million and $23 million for the nine months ended September 30, 2009 and 2008, respectively. Cash received from options exercised was $1 million and $2 million for the three months ended September 30, 2009 and 2008, respectively, and was $4 million and $11 million for the nine months ended September 30, 2009 and 2008, respectively. The estimated tax benefit from options exercised was less than $1 million and $1 million for the three months ended September 30, 2009 and 2008, respectively, and was $1 million and $5 million for the nine months ended September 30, 2009 and 2008, respectively.

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, 2008		78,517		$	56.45
Granted		101,451		$	21.47
Forfeited		(7,616	)	$	(28.94	)
Affiliate transfers – net		(1,253	)	$	(57.96	)
Nonvested at September 30, 2009		171,099		$	36.93

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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 "Pensions and benefits" on the consolidated balance sheets):

	Performance Shares			Weighted- Average Fair Value
	(Unaudited)
Nonvested at December 31, 2008		78,517
Granted		101,451
Forfeited		(7,616	)
Affiliate transfers – net		(1,253	)
Nonvested at September 30, 2009		171,099		$	24.45

Note 6. Commitments and Contingencies

The following is an update to SCE's commitments and contingencies. See Note 6 of "Notes to Consolidated Financial Statements" included in SCE's 2008 Annual Report on Form 10-K for a detailed discussion.

Lease Commitments

SCE has operating leases for power contracts and other operating leases for office space, vehicles, property and other equipment (with varying terms, provisions and expiration dates). SCE also has power purchase contracts which meet the requirements for capital leases and are reflected in "Utility plant" on the consolidated balance sheets. The gross amount of assets recorded in "Utility plant" for capital leases was $25 million at both September 30, 2009 and December 31, 2008. The asset carrying amount, net of amortization, was $13 million and $16 million at September 30, 2009 and December 31, 2008. The related obligations are reflected on the consolidated balance sheets as "Other current liabilities" and "Other deferred credits and other long-term liabilities." In addition, SCE has power purchase contracts which meet the requirements for capital leases, but are not reflected on the consolidated balance sheets since the lease terms begin in 2010. There are no sublease rentals and the contingent rentals for capital leases were less than $1 million for both the nine months ended September 30, 2009 and 2008. For additional discussion of these lease commitments, see Note 6 of "Notes to Consolidated Financial Statements" included in SCE's 2008 Annual Report on Form 10-K. The following are the estimated remaining commitments for noncancelable operating leases and all

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contracts that meet the requirements for capital leases (whether or not recorded on the consolidated balance sheets):

In millions	Operating Leases – Power Contracts		Operating Leases – Other		Capital Leases
	(Unaudited)
Year ending December 31,
2009 (remaining three months)	$	84	$	16	$	1
2010		626		49		96
2011		498		45		93
2012		361		39		120
2013		356		33		120
Thereafter		2,186		116		2,388
Total future commitments	$	4,111	$	298	$	2,818
Amount representing executory costs		—		—		(696	)
Amount representing interest		—		—		(402	)
Net commitments	$	4,111	$	298	$	1,720

Operating lease expense was $191 million and $161 million for the three months ended September 30, 2009 and 2008, respectively, and was $326 million and $303 million for the nine months ended September 30, 2009 and 2008, respectively.

Indemnities

Indemnity Provided as Part of the Acquisition of Mountainview

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

Mountainview Filter Cake Indemnity

The Mountainview 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. Mountainview 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

17

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 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.

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 (classified as "Other long-term liabilities") at undiscounted amounts.

As of September 30, 2009, SCE's recorded estimated minimum liability to remediate its 24 identified sites was $39 million, of which $5 million was related to San Onofre. 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 could exceed its recorded liability by up to $178 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 31 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to $10 million.

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The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $29 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 $40 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 $11 million to $30 million. Recorded costs were $2 million and $13 million for the three months ended September 30, 2009 and 2008, respectively, and $7 million and $23 million for the nine months ended September 30, 2009 and 2008, 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.

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 years 2008. Edison International's California and other state income tax returns remain open for tax years 1986 through 2008. As discussed in the section "Global Settlement" in Note 4, the Global Settlement was finalized on May 5, 2009 and effectively closed the federal income tax examination for tax years 1986 - 2002.

FERC Construction Work in Progress Mechanism (CWIP)

2008 CWIP

In February 2008, the FERC approved, subject to refund, SCE's request to collect 100% of CWIP in rate base for its Tehachapi, DCR, and Rancho Vista projects, which resulted in base transmission revenue billed of $37 million. In March 2008, the CPUC requested a rehearing with the FERC on the FERC's acceptance of SCE's proposed ROE for CWIP and in another 2008 protest to an SCE compliance filing, requested a hearing to be set to further review SCE's costs. SCE cannot predict the outcome of the matters in this proceeding.

2009 CWIP

In December 2008, the FERC approved SCE's CWIP rate adjustment which resulted in a CWIP revenue requirement of $39 million, effective on January 1, 2009, subject to refund as well as subject to the outcome of the pending 2008 FERC CWIP proceeding.

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Four Corners CPUC Emissions Performance Standard Ruling

The emission performance standards adopted by the CPUC and CEC pursuant to SB 1368 prohibit SCE and other California load-serving entities from entering into long-term financial commitments with generators that do not meet the emission performance standards, which would include most coal-fired plants. In January 2008, SCE filed a petition with the CPUC seeking clarification that the emission performance standard would not apply to capital expenditures required by existing agreements among the owners at Four Corners. The CPUC issued a proposed decision finding that the emission performance standard was not intended to apply to capital expenditures at Four Corners requested by SCE in its GRC for the period 2007 - 2011. In October 2008, the Assigned Commissioner and Administrative Law Judge issued a ruling withdrawing the proposed decision and seeking additional comment on whether the finding in the proposed decision should be changed and whether SCE should be allowed to recover such capital expenditures. SCE estimates that its share of capital expenditures approved by the owners at Four Corners since the GHG emission performance standard decision was issued in January 2007 is approximately $50 million, of which approximately $12 million had been expended through September 30, 2009. The ruling also directs SCE to explain why certain information was not included in its petition and why the failure to include such information should not be considered misleading in violation of CPUC rules. SCE cannot predict whether any amounts will be disallowed.

FERC Transmission Incentives

The Energy Policy Act of 2005 established incentive-based rate treatments for the transmission of electric energy in interstate commerce by public utilities. Pursuant to this act, in November 2007, the FERC issued an order granting incentives on three of SCE's largest proposed transmission projects. These include an incentive above SCE's otherwise-authorized return on equity of 125 basis points for SCE's DCR and Tehachapi transmission projects and 75 basis points for SCE's Rancho Vista Substation Project ("Rancho Vista"), as well as a 50 basis points adder on SCE's cost of capital for its entire transmission rate base for SCE's participation in the CAISO. In addition, the order on incentives permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction, also known as CWIP, of all three projects mentioned above and 100% recovery of prudently-incurred abandoned plant costs for DCR and Tehachapi, if either or both of these projects are cancelled due to factors beyond SCE's control. The CPUC is appealing the FERC incentives order but the appeal has been deferred until a final FERC order is issued in the 2008 CWIP case.

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. The complaint asserts claims for, among other things, violations of the federal RICO statute, 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, trebling of that amount, and punitive damages of not less than $1 billion. In March 2001, the Hopi Tribe was permitted to intervene as an additional plaintiff but has not yet identified a specific amount of damages claimed. The case was stayed at the request of the parties in October 2004, but was reinstated to the active calendar in March 2008. 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.

SCE cannot predict the outcome of the Tribes' complaints against SCE or the ultimate impact of the April 2009 U.S. Supreme Court decision on these complaints.

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Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $12.5 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($300 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site.

Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. Beginning October 29, 2008, the maximum deferred premium for each nuclear incident is approximately $118 million per reactor, but not more than approximately $18 million per reactor may be charged in any one year for each incident. The maximum deferred premium per reactor and the yearly assessment per reactor for each nuclear incident is adjusted for inflation at least once every five years. The most recent inflation adjustment took effect on October 29, 2008. 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. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. 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 $45 million per year. Insurance premiums are charged to operating expense.

Procurement of Renewable Resources

California law requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2010.

It is unlikely that SCE will have 20% of its annual electricity sales procured from renewable resources by 2010. However, SCE may still meet the 20% target by utilizing the flexible compliance rules, such as banking of past surplus and earmarking of future deliveries from executed contracts. SCE continues to engage in several renewable procurement activities including formal solicitations approved by the CPUC, bilateral negotiations with individual projects and other initiatives.

Under current CPUC decisions, potential penalties for SCE's inability to achieve its renewable procurement objectives for any year will be considered by the CPUC in the context of the CPUC's review of SCE's annual compliance filings. Under the CPUC's current rules, the maximum penalty for inability to achieve renewable procurement targets is $25 million per year. SCE does not believe it will be assessed penalties for 2008 or the prior years and cannot predict whether it will be assessed penalties for future years.

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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. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre (approximately $24 million, plus interest). SCE has also been paying a required quarterly fee equal to 0.1¢ per-kWh of nuclear-generated electricity sold after April 6, 1983. 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. SCE cannot predict the outcome of this proceeding or when a decision will be issued by the Court.

SCE, as operating agent, has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Such interim storage for San Onofre is on-site.

APS, as operating agent, has primary responsibility for the interim storage of spent nuclear fuel at Palo Verde. Palo Verde plans to add storage capacity incrementally to maintain full core off-load capability for all three units. In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed an independent spent fuel storage facility.

Note 7. Consolidated Statement of Changes in Equity

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

	Equity Attributable to SCE
In millions	Common Stock		Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Preferred and Preference Stock		Noncontrolling Interests			Total Equity
	(Unaudited)
Balance at December 31, 2008	$	2,168	$	532	$	(14	)	$	3,827		$	920	$	380		$	7,813
Net income		—		—		—			1,091			—		90			1,181
Other comprehensive income		—		—		1			—			—		—			1
Dividends declared on common stock		—		—		—			(200	)		—		—			(200	)
Dividends declared on preferred and preference stock not subject to mandatory redemption		—		—		—			(38	)		—		—			(38	)
Distributions to noncontrolling interests		—		—		—			—			—		(94	)		(94	)
Shares purchased for stock-based compensation		—		—		—			(6	)		—		—			(6	)
Proceeds from stock option exercises		—		—		—			4			—		—			4
Noncash stock-based compensation and other		—		10		—			(3	)		—		—			7
Excess tax benefits related to stock-based awards		—		6		—			—			—		—			6
Balance at September 30, 2009	$	2,168	$	548	$	(13	)	$	4,675		$	920	$	376		$	8,674

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The following table provides changes in equity for the nine months ended September 30, 2008:

	Equity Attributable to SCE
In millions	Common Stock		Additional Paid-in Capital		Accumulated Other Comprehensive Loss			Retained Earnings			Preferred and Preference Stock			Noncontrolling Interests			Total Equity
	(Unaudited)
Balance at December 31, 2007	$	2,168	$	507	$	(15	)	$	3,568		$	929		$	446		$	7,603
Net income		—		—		—			580			—			161			741
Other comprehensive loss		—		—		(2	)		—			—			—			(2	)
Dividends declared on common stock		—		—		—			(300	)		—			—			(300	)
Dividends declared on preferred and preference stock not subject to mandatory redemption		—		—		—			(38	)		—			—			(38	)
Preferred stock redeemed, net of gain		—		2		—			—			(9	)		—			(7	)
Distributions to noncontrolling interests		—		—		—			—			—			(156	)		(156	)
Shares purchased for stock-based compensation		—		—		—			(28	)		—			—			(28	)
Proceeds from stock option exercises		—		—		—			11			—			—			11
Noncash stock-based compensation and other		—		13		—			(5	)		—			—			8
Excess tax benefits related to stock-based awards		—		7		—			—			—			—			7
Balance at September 30, 2008	$	2,168	$	529	$	(17	)	$	3,788		$	920		$	451		$	7,839

Note 8. Property and Plant

On March 12, 2009, the CPUC issued a final decision in SCE's 2009 GRC, authorizing the transfer of the assets and liabilities of Mountainview Power Company, LLC, a 100% owned subsidiary of SCE, to SCE. SCE received FERC and other necessary approvals, and on July 1, 2009, terminated the FERC-approved power-purchase agreement between Mountainview Power Company, LLC and SCE, and transferred assets and liabilities valued at $680 million and $173 million, respectively. The transfer resulted in a $603 million increase in SCE's utility plant (primarily generation plant) with a corresponding decrease in nonutility property (primarily building, plant and equipment). In addition, SCE recognized a one time, non-cash accounting benefit of approximately $46 million primarily resulting from the establishment of regulatory assets to recognize differences in the accounting treatment for non-regulated and rate-regulated entities mainly related to equity AFUDC. There was no economic impact to customers from this change as compared to the FERC-approved power-purchase agreement; as these amounts would have been recognized over the life of that agreement and have no impact on cash flows.

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Note 9. Supplemental Cash Flows Information

SCE's supplemental cash flows information is:

		Nine Months Ended September 30,
In millions		2009			2008
		(Unaudited)
Cash payments for interest and taxes:
Interest – net of amounts capitalized		$	326		$	250
Tax payments (receipts)		$	(690	)	$	121
Noncash investing and financing activities:
Dividends declared but not paid:
	Common stock	$	100		$	100
	Preferred and preference stock not subject to mandatory redemption	$	8		$	13

Note 10. 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"). Authoritative guidance on fair value measurements and disclosures clarifies that a fair value measurement for a liability should reflect the entity's non-performance risk. In addition, a fair value hierarchy is established that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical asset 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, SCE nuclear decommissioning trust investments and money market funds. Derivative contracts primarily relate to 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. SCE's Level 2 derivatives primarily consist of financial natural gas swaps, fixed float 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.

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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 SCE 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 float 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, SCE reviews objective criteria related to system congestion and other underlying drivers and adjusts fair value when SCE concludes a change in objective criteria would result in a new valuation that better reflects the 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.

In assessing nonperformance risks, SCE reviews credit ratings of counterparties (and related default rates based on such credit ratings). At September 30, 2009, SCE reduced the fair value of derivative assets and derivative liabilities for nonperformance risks by $3 million and $10 million, respectively.

Investments in money market funds are generally classified as Level 1 as fair value is determined by observable market prices (unadjusted) in active markets.

The SCE 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 table sets forth assets and liabilities that were accounted for at fair value as of September 30, 2009 by level within the fair value hierarchy:

In millions			Level 1		Level 2			Level 3			Netting and Collateral(1)			Total
			(Unaudited)
Assets at Fair Value
	Money market funds(2)		$	647	$	—		$	—		$	—		$	647
	Derivative contracts			12		2			426			(8	)		432
	Long-term disability plan			8		—			—			—			8
	Nuclear decommissioning trusts(3)
		Municipal bonds		—		608			—			—			608
		Stocks		1,681		—			—			—			1,681
		United States government issues		262		39			—			—			301
		Corporate bonds		—		414			—			—			414
		Short-term investments, primarily cash equivalents				15			—			—			15
		Sub-total of nuclear decommissioning trusts	$	1,943	$	1,076		$	—		$	—		$	3,019
Total assets(4)			$	2,610	$	1,078		$	426		$	(8	)	$	4,106
Liabilities at Fair Value
	Derivative contracts			—		(144	)		(601	)		9			(736	)
Net assets (liabilities)			$	2,610	$	934		$	(175	)	$	1		$	3,370

The following table sets forth assets and liabilities that were accounted for at fair value as of December 31, 2008 by level within the fair value hierarchy:

In millions			Level 1			Level 2			Level 3			Netting and Collateral(1)		Total
			(Unaudited)
Assets at Fair Value
	Money market funds(2)		$	1,526		$	—		$	—		$	—	$	1,526
	Derivative contracts			2			2			227			—		231
	Long-term disability plan			7			—			—			—		7
	Nuclear decommissioning trusts(3)
		Municipal bonds		—			629			—			—		629
		Stocks		1,308			—			—			—		1,308
		United Stated government issues		172			132			—			—		304
		Corporate bonds		—			260			—			—		260
		Short-term investments, primarily cash equivalents		4			23			—			—		27
		Sub-total of nuclear decommissioning trusts	$	1,484		$	1,044		$	—		$	—	$	2,528
Total assets(4)			$	3,019		$	1,046		$	227		$	—	$	4,292
Liabilities at Fair Value
	Derivative contracts			(2	)		(219	)		(745	)		72		(894	)
Net assets (liabilities)			$	3,017		$	827		$	(518	)	$	72	$	3,398

(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)

Excludes net assets/(liabilities) of $6 million and $(4) million at September 30, 2009 and December 31, 2008, respectively, of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases.

(4)

Excludes $32 million at both September 30, 2009 and December 31, 2008, of cash surrender value of life insurance investments for deferred compensation.

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The following table sets forth a summary of changes in the fair value of Level 3 financial instruments:

		Three Months Ended September 30,						Nine Months Ended September 30,
In millions		2009			2008			2009			2008
		(Unaudited)
Fair value, net at beginning of period		$	117		$	265		$	(518	)	$	(22	)
Total realized/unrealized gains (losses):
	Included in regulatory assets and liabilities(1)		(322	)		(264	)		270			(99	)
Purchases and settlements, net			5			20			48			142
Transfers in or out of Level 3			25			—			25			—
Fair value, net		$	(175	)	$	21		$	(175	)	$	21
Change during the period in unrealized gains (losses) related to financial instruments held at the end of the period		$	(319	)	$	(180	)	$	302		$	(70	)

(1)

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

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 trusts. 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	September 30, 2009		December 31, 2008		September 30, 2009		December 31, 2008
		(Unaudited)
Municipal bonds	2009 – 2042	$	513	$	561	$	608	$	629
Stocks	–		825		839		1,681		1,308
United States government issues	2009 – 2051		280		268		301		304
Corporate bonds	2009 – 2049		325		214		414		260
Short-term investments, primarily cash equivalents	2009		20		24		21		23
Total		$	1,963	$	1,906	$	3,025	$	2,524

Note: Maturity dates as of September 30, 2009.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Realized gains were $35 million and $43 million for the three months ended September 30, 2009 and 2008, respectively and $223 million and $96 million for the nine months ended September 30, 2009 and 2008, respectively. Realized losses were $3 million and $40 million for the three months ended September 30, 2009 and 2008, respectively and $142 million and $46 million for the nine months ended September 30, 2009 and 2008, respectively. Proceeds from sales of securities (which are reinvested) were $503 million and $778 million for the three months ended September 30, 2009 and 2008, respectively and $1.8 billion and $2.3 billion for the nine months ended September 30, 2009 and 2008, respectively. Unrealized holding gains, net of losses, were $1.1 billion and $618 million

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at September 30, 2009 and December 31, 2008, 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 for the nine months ended September 30, 2009:

In millions	2009
	(Unaudited)
Balance at December 31, 2008	$	2,524
Realized gains – net		81
Unrealized gains – net		444
Other-than-temporary impairments		(105	)
Interest, dividends, contributions and other		81
Balance at September 30, 2009	$	3,025

Due to regulatory mechanisms, changes in the fair value of the trust have no impact on operating revenue. SCE reviews each security for other-than-temporary impairment losses on the last day of the current month and the last day of the previous month. If the fair value on both days is less than the cost for that security, SCE recognizes a loss for the other-than-temporary impairment. If the fair value is greater or less than the cost for that security at the time of sale, SCE recognizes a related realized gain or loss, respectively.

Nuclear decommissioning costs are recovered in utility rates. These costs are expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately $46 million per year. Contributions to the decommissioning trusts are reviewed approximately every three years by the CPUC. These contributions are determined based on an analysis of the liquidation value of the trusts, long-term forecasts of cost escalation, the estimate and timing of decommissioning costs, and after-tax return on trust investments. Favorable or unfavorable investment performance during the intervening period will not change the amount of contributions for that period. However, trust performance for the three years leading up to a CPUC review proceeding will provide input into future contributions. On April 3, 2009, SCE submitted its triennial nuclear decommissioning application, requesting that its trust fund contributions increase to approximately $64.5 million per year, beginning on January 1, 2011. The CPUC has set certain restrictions related to the investments of these trusts. If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through customer rates.

Long-term Debt

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

	September 30, 2009				December 31, 2008
In millions	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Unaudited)
Long-term debt, including current portion	$	6,740	$	7,422	$	6,362	$	6,717

Fair values of long-term debt are based on bank evaluations.

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Note 11. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

In millions	September 30, 2009		December 31, 2008
	(Unaudited)
Current:
Regulatory balancing accounts	$	47	$	455
Energy derivatives		8		138
Other		2		12
	$	57	$	605
Long-term:
Regulatory balancing accounts	$	42	$	29
Flow-through taxes – net		1,529		1,337
ARO		—		224
Unamortized nuclear investment – net		352		375
Nuclear-related ARO investment – net		263		278
Unamortized coal plant investment – net		75		79
Unamortized loss on reacquired debt		293		309
SFAS No. 158 pensions and postretirement benefits		1,907		1,882
Energy derivatives		446		723
Environmental remediation		40		40
Other		137		138
	$	5,084	$	5,414
Total Regulatory Assets	$	5,141	$	6,019

Regulatory liabilities included on the consolidated balance sheets are:

In millions	September 30, 2009		December 31, 2008
	(Unaudited)
Current:
Regulatory balancing accounts	$	1,146	$	1,068
Other		30		43
	$	1,176	$	1,111
Long-term:
Regulatory balancing accounts	$	33	$	43
ARO		132		—
Costs of removal		2,501		2,368
Employee benefit plans		182		70
	$	2,848	$	2,481
Total Regulatory Liabilities	$	4,024	$	3,592

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Note 12. Variable Interest Entities

Projects or Entities that are Consolidated

SCE has variable interests in contracts with certain QFs that contain variable contract pricing provisions based on the price of natural gas. Four of these contracts are with entities that are partnerships owned in part by a related party, EME. SCE has determined that it is the primary beneficiary of these four variable interest entities and therefore consolidates these projects.

In determining that SCE was the primary beneficiary, SCE considered the term of the contract, percentage of plant capacity, pricing, and other variable interests. SCE performed a quantitative assessment which included the analysis of the expected losses and expected residual returns of the entity by using the various estimated projected cash flow scenarios associated with the assets and activities of that entity. The quantitative analysis provided sufficient evidence to determine that SCE was the primary beneficiary absorbing a majority of the entity's expected losses, receiving a majority of the entity's expected residual returns, or both.

Project	Capacity		Termination Date(1)		EME Ownership
	(Unaudited)
Kern River		300 MW		June 2011		50%
Midway-Sunset		225 MW		May 2009		50%
Sycamore		300 MW		December 2007		50%
Watson		385 MW		December 2007		49%

(1)

SCE's power purchase agreements with Sycamore and Watson expired on December 31, 2007. In addition, SCE's power purchase agreement with Midway-Sunset expired on May 7, 2009. These three projects are currently selling electricity to SCE under the terms and conditions contained in its prior long-term power purchase agreement, with revised pricing terms as mandated by the CPUC. On September 28, 2009, Midway-Sunset entered into a power purchase agreement with Pacific Gas and Electric Company, subject to California Public Utilities Commission approval.

These four projects do not have any third party debt outstanding. SCE has no investment in, nor obligation to provide support to, these entities other than its requirement to make contract payments. Any profit or loss generated by these entities will not affect SCE's income statement. Any liabilities of these projects are nonrecourse to SCE. See Note 13 for carrying value and classification of the VIEs' assets and liabilities.

Entities with Unavailable Financial Information

SCE also has seven other contracts with QFs that contain variable pricing provisions based on the price of natural gas and are potential VIEs. SCE might be considered to be the consolidating entity under this standard and continues to attempt to obtain information for these projects in order to determine whether the projects should be consolidated. These entities are not legally obligated to provide financial information to SCE and have declined to do so. Because these potential VIEs were created prior to December 31, 2003, SCE is not required to apply this accounting guidance to these entities as long as SCE continues to be unable to obtain this information. The aggregate capacity dedicated to SCE for these projects is 270 MW and 263 MW at September 30, 2009 and December 31, 2008, respectively. The amounts that SCE paid to these projects were $43 million and $73 million for the three months ended September 30, 2009 and 2008, respectively, and $104 million and $171 million for the nine months ended September 30, 2009 and 2008, respectively. These amounts are recoverable in utility customer rates. SCE has no exposure to loss as a result of its involvement with these projects.

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Note 13. Business Segments

SCE's reportable business segments include the rate-regulated electric utility segment and the VIEs segment. The VIEs are gas-fired power plants that sell both electricity and steam. The VIE segment consists of non-rate-regulated entities (all in California). SCE's management has no control over the resources allocated to the VIE segment and does not make decisions about its performance.

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

In millions	Electric Utility		VIEs		Eliminations			SCE
	(Unaudited)
Balance Sheet Items as of September 30, 2009:
Cash and equivalents	$	660	$	94	$	—		$	754
Accounts receivable – net		934		55		(37	)		952
Inventory		314		18		—			332
Other current assets		123		4		—			127
Nonutility property – net of depreciation		71		259		—			330
Other long-term assets		499		4		—			503
Total assets		32,757		434		(37	)		33,154
Accounts payable		885		40		(37	)		888
Other current liabilities		606		2		—			608
Asset retirement obligations		3,121		16		—			3,137
Noncontrolling interests		—		376		—			376
Total liabilities and equity	$	32,757	$	434	$	(37	)	$	33,154
Balance Sheet Items as of December 31, 2008:
Cash and equivalents	$	1,522	$	89	$	—		$	1,611
Accounts receivable – net		679		63		(39	)		703
Inventory		346		19		—			365
Other current assets		279		4		—			283
Nonutility property – net of depreciation		671		282		—			953
Other long-term assets		363		1		—			364
Total assets		32,149		458		(39	)		32,568
Accounts payable		926		61		(39	)		948
Other current liabilities		570		2		—			572
Asset retirement obligations		2,992		15		—			3,007
Noncontrolling interests		—		380		—			380
Total liabilities and equity	$	32,149	$	458	$	(39	)	$	32,568

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SCE's consolidated statements of income, by business segment, are presented below:

In millions	Electric Utility			VIEs			Eliminations(1)			SCE
	(Unaudited)
Income Statement Items for the Three Months Ended September 30, 2009:
Operating revenue	$	3,021		$	166		$	(118	)	$	3,069
Fuel		97			80			—			177
Purchased power		1,150			—			(118	)		1,032
Other operation and maintenance		780			22			—			802
Depreciation, decommissioning and amortization		294			8			—			302
Property and other taxes		60			—			—			60
Total operating expenses		2,381			110			(118	)		2,373
Operating income		640			56			—			696
Interest income		4			—			—			4
Other nonoperating income		69			—			—			69
Interest expense – net of amounts capitalized		(105	)		—			—			(105	)
Other nonoperating deductions		(13	)		—			—			(13	)
Income tax expense		(236	)		—			—			(236	)
Net income		359			56			—			415
Net income attributable to noncontrolling interest		—			(56	)		—			(56	)
Dividends on preferred and preference stock not subject to mandatory redemption		(13	)		—			—			(13	)
Net income available for common stock	$	346		$	—		$	—		$	346
Income Statement Items for the Three Months Ended September 30, 2008:
Operating revenue	$	3,339		$	358		$	(229	)	$	3,468
Fuel		173			242			—			415
Purchased power		1,562			—			(229	)		1,333
Other operation and maintenance		707			14			—			721
Depreciation, decommissioning and amortization		268			8			—			276
Property and other taxes		61			—			—			61
Gain on sale of assets		(1	)		—			—			(1	)
Total operating expenses		2,770			264			(229	)		2,805
Operating income		569			94			—			663
Interest income		2			—			—			2
Other nonoperating income		20			—			—			20
Interest expense – net of amounts capitalized		(104	)		—			—			(104	)
Other nonoperating deductions		(81	)		—			—			(81	)
Income tax expense		(158	)		—			—			(158	)
Net income		248			94			—			342
Net income attributable to noncontrolling interest		—			(94	)		—			(94	)
Dividends on preferred and preference stock not subject to mandatory redemption		(13	)		—			—			(13	)
Net income available for common stock	$	235		$	—		$	—		$	235

(1)

VIE segment revenue includes sales to the electric utility segment, which are eliminated in revenue and purchased power in the consolidated statements of income.

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In millions	Electric Utility			VIEs			Eliminations(1)			SCE
	(Unaudited)
Income Statement Items for the Nine Months Ended September 30, 2009:
Operating revenue	$	7,377		$	440		$	(286	)	$	7,531
Fuel		276			257			—			533
Purchased power		2,441			—			(286	)		2,155
Other operation and maintenance		2,154			68			—			2,222
Depreciation, decommissioning and amortization		852			25			—			877
Property and other taxes		187			—			—			187
Gain on sale of assets		(1	)		—			—			(1	)
Total operating expenses		5,909			350			(286	)		5,973
Operating income		1,468			90			—			1,558
Interest income		9			—			—			9
Other nonoperating income		126			—			—			126
Interest expense – net of amounts capitalized		(320	)		—			—			(320	)
Other nonoperating deductions		(33	)		—			—			(33	)
Income tax expense		(159	)(2)		—			—			(159	)
Net income		1,091			90			—			1,181
Net income attributable to noncontrolling interest		—			(90	)		—			(90	)
Dividends on preferred and preference stock not subject to mandatory redemption		(38	)		—			—			(38	)
Net income available for common stock	$	1,053		$	—		$	—		$	1,053
Income Statement Items for the Nine Months Ended September 30, 2008:
Operating revenue	$	8,355		$	933		$	(590	)	$	8,698
Fuel		480			681			—			1,161
Purchased power		3,643			—			(590	)		3,053
Other operation and maintenance		2,076			69			—			2,145
Depreciation, decommissioning and amortization		804			26			—			830
Property and other taxes		179			—			—			179
Gain on sale of assets		(9	)		—			—			(9	)
Total operating expenses		7,173			776			(590	)		7,359
Operating income		1,182			157			—			1,339
Interest income		10			2			—			12
Other nonoperating income		67			2			—			69
Interest expense – net of amounts capitalized		(297	)		—			—			(297	)
Other nonoperating deductions		(114	)		—			—			(114	)
Income tax expense		(268	)		—			—			(268	)
Net income		580			161			—			741
Net income attributable to noncontrolling interest		—			(161	)		—			(161	)
Dividends on preferred and preference stock not subject to mandatory redemption		(38	)		—			—			(38	)
Net income available for common stock	$	542		$	—		$	—		$	542

(1)

VIE segment revenue includes sales to the electric utility segment, which are eliminated in revenue and purchased power in the consolidated statements of income.

(2)

Includes income tax benefit of $300 million related to the Global Settlement. See Note 4.

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

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:

•

the cost of capital and the ability to borrow funds and access to capital markets on reasonable terms;

•

the effect of current economic conditions on the 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;

•

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;

•

the 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, rates of inflation including those rates which may be adjusted by public utility regulators, and foreign exchange rates;

•

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 ISOs and regional transmission organizations;

•

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;

•

risks associated with operating nuclear and other power generating facilities, including operating risks, nuclear fuel storage, equipment failure, availability, heat rate, output, availability and cost of spare parts, and cost of repairs and retrofits;

•

the 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;

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•

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

•

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

•

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

•

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

•

the 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;

•

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

•

the risk of counterparty default in hedging transactions or power-purchase and fuel contracts;

•

general political, economic and business conditions;

•

weather conditions, natural disasters and other unforeseen events;

•

the risks inherent in undertaking large, complex generation projects and transmission and distribution infrastructure replacement and expansion projects including those related to siting, financing, construction, permitting, and governmental approvals; and

•

the risk that competing transmission systems will be built by merchant transmission providers in SCE's service 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. 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 & Exchange Commission.

This MD&A for the three- and nine-month periods ended September 30, 2009 discusses material changes in the consolidated financial condition, results of operations and other developments of SCE since December 31, 2008, and as compared to the three- and nine-month periods ended September 30, 2008. This discussion presumes that the reader has read or has access to SCE's MD&A for the calendar year 2008 (the year-ended 2008 MD&A), which was included in SCE's 2008 Annual Report to shareholders and incorporated by reference into SCE's Annual Report on Form 10-K for the year ended December 31, 2008 and Current Report on Form 8-K filed with the Securities and Exchange Commission on March 2, 2009 and August 14, 2009, respectively.

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MANAGEMENT OVERVIEW

Areas of Business Focus

2010 FERC Rate Case

On September 30, 2009, FERC issued an order accepting SCE's proposed 2010 base transmission rates, subject to refund and settlement procedures, and made the rates effective March 1, 2010. The proposed base transmission rates will increase SCE's revenue requirement by $107 million, or 24%, over the 2009 base transmission revenue requirement primarily due to an increase in transmission rate base. The proposed rates, if approved, are expected to result in an approximate 1% increase to SCE's overall system average rate.

Cost of Capital Mechanism

The CPUC determines SCE's cost of capital in a multi-year proceeding occurring every three years. This cost of capital mechanism allows for an annual adjustment to SCE's capital costs if certain thresholds are reached. On October 15, 2009, the CPUC approved SCE's request to forgo an expected 2010 cost of capital increase under the annual adjustment provision and extended SCE's existing capital structure and authorized rate of return through December 2012, absent any future potential annual adjustments. The revised mechanism will be subject to CPUC review in 2012 for the cost of capital set for 2013 and beyond.

Business Development and Capital Commitments

SCE's growth strategy includes infrastructure reliability investments and expanding the capability of its distribution and transmission infrastructure, constructing and replacing generation assets, and deploying advanced metering infrastructure. SCE continues to advance its growth strategy included in its 2009 – 2013 capital investment plan. SCE's significant planned projects are as follows:

Transmission and Distribution Projects

•

Devers-Colorado River Project – A transmission project that, as modified, would install a high voltage (500 kV) transmission line from Romoland, California to the Colorado River switchyard east of Blythe, California. The project is currently expected to be placed in service in 2013, subject to final licensing and regulatory approvals. Over the period 2009 – 2013, SCE expects to spend $637 million for the project, excluding the previously proposed Arizona portion of the project. The originally proposed project would have continued the transmission line through a portion of west Arizona, but due to a denial by the Arizona Corporation Commission the project was modified. SCE no longer plans to pursue construction of the Arizona portion at this time but continues to evaluate its transmission needs in western Arizona.

•

Tehachapi Transmission Project – An eleven segment project consisting of new and upgraded transmission lines and associated substations built primarily to enable the development of renewable energy generated primarily by wind farms in remote areas of eastern Kern County, California. Tehachapi segments one through three are under construction and are expected to be placed in service at various dates over the next two years. SCE continues to seek the necessary licensing permits for Tehachapi segments four through eleven, which are expected to be placed in service between 2011 and 2015, subject to receipt of licensing and regulatory approvals. SCE expects to spend $2.0 billion over the period 2009 – 2013 on this project.

•

Eldorado-Ivanpah Transmission Project – A proposed 220/115 kV substation near Primm, Nevada and an upgrade of a 35-mile portion of an existing transmission line connecting the new substation to the Eldorado Substation, near Boulder City, Nevada. Over the period 2009 – 2013, SCE expects to

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spend $464 million for the project. On October 1, 2009, SCE filed a request for incentives at FERC for the Eldorado-Ivanpah Transmission Project. SCE requested 100% abandoned plant recovery, 100% CWIP recovery, and a 150 basis point ROE project adder.

•

EdisonSmartConnect™ – SCE's advanced metering project that will install "smart" meters in approximately 5.3 million households and small businesses throughout its service territory. SCE began full deployment of meters in 2009, and anticipates completion of the deployment in 2012. SCE estimates capital costs of $1.2 billion over the period 2009 – 2012.

•

Other capital investments consisting of $1.8 billion for transmission development and $10.1 billion for distribution projects to improve reliability and expand capability of its infrastructure over the period 2009 – 2013.

Generation Projects

•

San Onofre Steam Generator Replacement Project – Recently, SCE took delivery of the first two of four steam generators which are expected to be placed in service in the fourth quarter of 2009. The project is intended to enable San Onofre to operate until the end of its initial license period in 2022, and beyond if license renewal proves feasible. SCE expects to spend $459 million over the period 2009 – 2011.

•

Solar Photovoltaic Program – In June 2009, the CPUC issued a final decision approving a program to develop 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 rooftop and other space in SCE's service territory. The final decision also ordered SCE to solicit power purchase agreements from independent power producers for an additional 250 MW of rooftop solar photovoltaic power. SCE expects to spend $817 million over the period 2009 – 2013.

SCE's 2009 – 2013 total capital investment plan includes capital spending in the range of $16.8 billion to $19.8 billion. See "Liquidity—Capital Expenditures" for further discussion.

Greenhouse Gas Regulation

Legislative, regulatory and legal developments related to potential controls over GHG emissions in the United States are ongoing. Actions to limit or reduce GHG emissions could significantly increase the cost of generating electricity from fossil fuels as well as the cost of purchased power. In the case of utilities, like SCE, these costs are generally borne by customers.

Legislation to regulate GHG emissions continues to be considered by the Congress; however, the timing, content, and potential effects on SCE of any climate change legislation that may be enacted remain uncertain. In June 2009, the American Clean Energy and Security Act was passed by the U.S. House of Representatives. The bill, which was endorsed by SCE's parent company, Edison International, would establish a 20% mandatory federal combined efficiency and renewable electricity standard for certain retail electricity suppliers (SCE is already subject to a California law that requires California utilities to procure at least 20% of their annual electricity sales from renewable resources by 2010) and establish a cap-and-trade system for carbon emissions commencing in 2012. Under the cap-and-trade system, a cap to reduce aggregate GHG emissions from all covered entities would be established and decline over time. Emitters of GHGs would be required to have allowances for GHG emissions emitted during a relevant measurement period. The bill would provide for stated portions of required allowances to be allocated free of charge in declining amounts over time. Emitters of GHGs would have to purchase the remainder of their required allowances in the open market, although a portion may be provided by so-called offset credits (for alternative GHG conservation efforts).

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In April 2009, the US EPA responded to the 2007 U.S. Supreme Court decision in Massachusetts v. EPA by issuing a proposed finding that the current and projected concentrations of the mix of six key GHGs, including carbon dioxide, in the atmosphere threaten the public health and welfare of current and future generations and that such GHGs were air pollutants covered by the CAA. In September 2009, the US EPA issued its Final Mandatory Greenhouse Gas Reporting Rule, which will require all sources within specified categories, including electric generation facilities, to begin emissions monitoring in January 2010, and to submit annual reports to the US EPA by March 31 of each year, with the first report due on March 31, 2011. In September 2009, the US EPA also issued a proposed rule, known as the "tailoring rule," that if adopted would require new facilities with a potential to emit over 25,000 tons of GHGs per year (major GHG sources), or existing major GHG sources emitting over 25,000 tons of GHGs per year that are modified and, as a result, increase their potential GHG emissions by over 10,000 tons per year, to obtain pre-construction permits that would demonstrate that they are using best available control technologies to minimize their GHG emissions. If controls are required to be installed at the facilities of SCE in the future in order to reduce GHG emissions pursuant to regulations issued by the US EPA or others, the potential impact will depend on the nature of the controls applied, which remains uncertain.

Three courts recently addressed the question of whether power plants that emit GHGs constituted public nuisances that could be held liable for damages or other remedies. In one case (in which SCE's parent company, Edison International is a named defendant), a California federal district court dismissed the plaintiffs' claims. In the other two, federal courts of appeals permitted the suits to go forward. These differing results remain subject to appeal and thus the ultimate impact of these cases remains uncertain. SCE cannot predict whether these recent appellate decisions will result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts for these sorts of claims. For further discussion, see "Other Developments—Environmental Matters—Climate Change—Litigation Developments."

In California, the Governor issued an executive order in September directing the CARB to adopt a regulation by July 31, 2010 that would require utilities to procure at least 33% of their annual electricity sales from renewable resources by 2020. The Order provides that the regulation could increase the targeted percentage of annual electricity sales to be obtained from renewable resources, as well as accelerate or expand the timeframe for compliance based on a thorough assessment of relevant factors. The resulting CARB regulations would be in addition to existing California law that requires California utilities to procure at least 20% of their annual electricity sales from renewable resources by 2010.

Global Settlement

As previously disclosed, Edison International and the IRS finalized the terms of a Global Settlement on May 5, 2009. The Global Settlement resolved all of SCE's federal income tax disputes and affirmative claims through tax year 2002. During the second quarter of 2009, SCE recorded after-tax earnings of approximately $300 million reflected in "Income tax expense" on the consolidated statements of income, primarily related to settlement of two affirmative claims associated with: (1) the taxation of balancing account overcollections; (2) and taxation of proceeds received in consideration for transferring control of SCE's transmission system to the CAISO and allowing direct access to SCE's distribution system, which were mandated as part of California's deregulation process. Both claims created tax timing differences that resulted in an interest refund from the IRS for prior period tax overpayments, but did not result in a permanent reduction in Edison International's and SCE's federal income tax liability. SCE expects an overall positive cash impact resulting from the Global Settlement of approximately $640 million over time, including the cash benefit of prior tax deposits of approximately $200 million (see "Liquidity—Intercompany Tax-Allocation Agreement" for further discussion).

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Edison International is addressing the impacts of the Global Settlement with state tax authorities and is awaiting final interest calculations from the IRS. Resolution of such matters with such authorities may change the estimated cash and earnings impacts described above.

Earnings Performance

SCE's net income available for common stock was $346 million and $1.1 billion for the three- and nine-month periods ended September 30, 2009, respectively, compared to $235 million and $542 million for the respective periods in 2008. The year-to-date variance reflects the impact of the Global Settlement which resulted in after-tax earnings of $300 million in 2009 (see "—Global Settlement" for further discussion), a non-cash accounting benefit of $46 million, in the third quarter of 2009 related to the transfer of the Mountainview power plant to utility rate base, and a charge of $49 million in the third quarter of 2008 resulting from the CPUC performance-based ratemaking decision. Excluding these items, SCE's quarter and year-to-date earnings reflect higher operating income related to the 2009 GRC decision and lower nonoperating expenses, partially offset by higher income taxes.

REGULATORY MATTERS

Current Regulatory Developments

This section of the MD&A describes significant updates to the regulatory matters disclosed in the year-ended 2008 MD&A.

Impact of Regulatory Matters on Customer Rates

On October 1, 2009, SCE's system average rate increased to 14.2¢ per-kWh from 14.1¢ per-kWh due to the implementation of both revenue allocation and rate design changes authorized in Phase 2 of the 2009 GRC and the FERC transmission rate changes authorized in the 2009 FERC rate case.

As discussed in the year-ended 2008 MD&A under the heading "Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates," a California law ("AB 1X") capped customer rates for almost half of SCE's residential customers. On October 11, 2009, California Governor Schwarzenegger signed a bill into law that will allow SCE and other investor-owned utilities to spread future rate increases more broadly among their residential customers. The bill also provides for a limited, phased-in expansion of direct access for nonresidential customers. These changes are not expected to impact SCE's earnings or cash flows.

2009 General Rate Case Proceeding

On March 12, 2009, the CPUC issued a final decision in SCE's 2009 GRC, authorizing a $4.83 billion base revenue requirement for 2009. The CPUC also authorized a methodology for calculating post-test year revenue requirements that would result in an approximate base revenue requirement of $5.04 billion in 2010 and $5.25 billion in 2011. In addition, the 2009 GRC decision establishes new balancing account regulatory treatment for SCE's medical, dental, and vision expenses, and its share of Palo Verde operation and maintenance expenses, and modifies SCE's existing pension and PBOP balancing accounts to allow annual recovery or refund of the recorded year-end balances. During the first quarter of 2009, SCE implemented the updated revenue requirement retroactive to January 1, 2009 consistent with the CPUC authorization. In addition, SCE revised its capital expenditure forecasts for the period 2009 – 2013. See "Liquidity—Capital Expenditures" for further discussion.

2009 FERC Rate Case

On September 11, 2009, the FERC approved a settlement between SCE and the parties to the FERC rate case on the 2009 base transmission rates, effective March 1, 2009. The settlement provides for a

39

base transmission revenue requirement of $448 million, which increases SCE's revenue requirement by $136 million over the previously authorized base transmission revenue requirement.

Energy Efficiency Shareholder Risk/Reward Incentive Mechanism

As discussed under the heading "Regulatory Matters—Current Regulatory Developments—Energy Efficiency Shareholder Risk/Reward Incentive Mechanism," in the year-ended 2008 MD&A, the CPUC has adopted an Energy Efficiency Risk/Reward Incentive Mechanism. Under the adopted mechanism, SCE would expect to receive a CPUC decision and record its 2006 – 2008 program cycle second progress payment, estimated in the range of $14 million to $26 million, in the fourth quarter of 2009 and would collect the payment in rates during 2010. In a related CPUC rulemaking proceeding, SCE proposed finalizing the total earnings for the 2006 – 2008 program cycle and collecting all remaining payments in 2010 and 2011. There is no assurance of earnings in any given year and SCE cannot predict whether the CPUC will change the adopted mechanism in the related rulemaking proceeding.

OTHER DEVELOPMENTS

Environmental Matters

For a discussion of SCE's environmental matters, refer to "Other Developments—Environmental Matters" in the year-ended 2008 MD&A. There have been no significant developments with respect to environmental matters affecting SCE since the filing of SCE's Annual Report on Form 10-K, except as follows:

Climate Change

Litigation Developments

On October 15, 2009, a California federal district court dismissed the complaint that had been filed by the native Alaskan village of Kivalina and the Kivalina Tribe in February 2008 against numerous defendants, including Edison International, principally in the oil and energy industries. Although SCE was not named as a defendant, the complaint identified SCE as a direct or indirect operating subsidiary of Edison International through which Edison International engages in electric power generation. Plaintiffs had alleged GHG emissions from the defendants' business activities contributed to global warming impacts that are melting the Arctic sea ice that protects the village from winter storms. The court dismissed the plaintiffs' federal nuisance claims stating that they were inappropriate for judicial resolution because they required policy choices that were reserved to the legislative or executive branches of the government (the "political question doctrine"). The court also held that the plaintiffs did not have standing to bring the case, in part because of the lack of connection between the defendants' conduct and the harm that plaintiffs alleged was occurring. The court also dismissed plaintiffs' state law nuisance claims, but without prejudice to those claims being re-filed in state court.

Recently, however, the federal Second Circuit and Fifth Circuit Courts of Appeals both issued decisions in cases against GHG emitters, which concluded that plaintiffs in those cases did have standing to bring nuisance claims and that those claims were not precluded by the political question doctrine.

In 2004, several states and environmental organizations filed a complaint in a federal district court in New York, alleging that several electric utilities (which did not include SCE) were liable under a theory of public nuisance for damages caused by the alleged contribution to global warming resulting from carbon dioxide emissions from coal-fired power plants owned and operated by these companies or their subsidiaries. The power plants that were the subject of the complaint were not located in physical proximity to the plaintiffs. On September 21, 2009, the Second Circuit Court of Appeals reinstated the lawsuit, holding that the plaintiffs had standing and that their claims did not violate the political question doctrine.

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On October 16, 2009, the United States Court of Appeals for the Fifth Circuit reinstated a class action lawsuit that had been dismissed by a federal district court in Mississippi. The plaintiffs claimed that emissions of GHGs from fossil fuel-fired electric generation and other operations allegedly contributed to the destructive force of Hurricane Katrina. The Fifth Circuit decision would allow the plaintiffs to continue to pursue their state law claims of public and private nuisance, trespass and negligence. At the time the action was dismissed by the court in Mississippi, the plaintiffs were seeking to amend their complaint to include Edison International and several affiliates of Edison International, including SCE, as defendants.

SCE cannot predict whether, and to what extent, any of these decisions will be cited as precedent in other similar lawsuits or result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts as sources of remedies for these sorts of claims.

US EPA Greenhouse Gas Regulation

In April 2009, the US EPA responded to the 2007 U.S. Supreme Court decision in Massachusetts v. EPA by issuing a proposed finding that the current and projected concentrations of the mix of six key GHGs, including carbon dioxide, in the atmosphere threaten the public health and welfare of current and future generations and that such GHGs were air pollutants covered by the CAA. In September 2009, the US EPA issued its Final Mandatory Greenhouse Gas Reporting Rule, which will require all sources within specified categories, including electric generation facilities, to begin emissions monitoring in January 2010, and to submit annual reports to the US EPA by March 31 of each year, with the first report due on March 31, 2011. In September 2009, the US EPA also issued a proposed rule, known as the "tailoring rule," that if adopted would require new facilities with a potential to emit over 25,000 tons of GHGs per year (major GHG sources), or existing major GHG sources emitting over 25,000 tons of GHGs per year that are modified and, as a result, increase their potential GHG emissions by over 10,000 tons per year, to obtain pre-construction permits that would demonstrate that they are using best available control technologies to minimize their GHG emissions.

Air Quality Regulation

New Source Review Requirements – Four Corners Section 114 Information Request

In April 2009, APS received a US EPA request pursuant to Section 114 of the CAA for information about Four Corners, where SCE is 48% owner of generating units 4 and 5 of Four Corners and APS is a part owner and the operating agent. The US EPA requested information about the Four Corners plant and its operations, including information about Four Corners capital projects from 1990 to the present. APS has responded to the US EPA request. SCE understands that in other cases the US EPA has utilized similar Section 114 letters for examining whether power plants have triggered New Source Review requirements under the CAA and are therefore potentially subject to more stringent air pollution control requirements. However, other than this request for information, no New Source Review enforcement-related proceedings have been initiated by the US EPA with respect to Four Corners. SCE cannot predict the outcome of this inquiry.

Water Quality Regulation

Clean Water Act – Cooling Water Standards and Regulations

In January 2007, the Second Circuit rejected the US EPA rule on cooling water intake structures and remanded it to the US EPA. Among the key provisions remanded by the court were the use of cost-benefit analysis for determining the best technology available and the use of restoration to achieve compliance with the rule. On July 2007, the US EPA suspended the requirements for cooling water intake structures, pending further rulemaking. In April 2009, the U.S. Supreme Court reversed the

41

Second Circuit and held that the US EPA may consider, but is not required to use, cost-benefit analysis in formulating regulations under Clean Water Act Section 316(b). The Court did not grant review of the Second Circuit's rejection of the use of restoration as compliance, which means the Second Circuit decision on this issue remains valid. It is unknown whether the US EPA will use cost-benefit analysis when it revises the regulations.

Clean Water Act – Prohibition on the Use of Ocean-Based Once-Through Cooling

In June 2009 the California State Water Resources Control Board released its draft "Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling." The draft policy would establish closed-cycle wet cooling as the best technology available for retrofitting existing once through cooled plants like San Onofre. The Board's stated goal is to vote on a final policy in December 2009. If the draft policy is adopted, it may significantly impact both operations at San Onofre and SCE's ability to procure timely generating capacity from fossil-fuel plants that use ocean water in once-through cooling systems as well as system reliability if other coastal plants are forced to shutdown.

Environmental Remediation

As of September 30, 2009, SCE's recorded estimated minimum liability to remediate its 24 identified sites was $39 million, of which $5 million was related to San Onofre. 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 could exceed its recorded liability by up to $178 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 31 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to $10 million.

The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $29 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 $40 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 $11 million to $30 million. Recorded costs were $2 million and $13 million for the three months ended September 30, 2009 and 2008, respectively, and $7 million and $23 million for the nine months ended September 30, 2009 and 2008, respectively.

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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 or financial position. 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.

Wildfire Insurance Issues

As discussed in the year-ended 2008 MD&A under the heading "Other Developments—Wildfire Insurance Issues," recent damage claims related to wildfires in California and the strict liability doctrine of inverse condemnation may affect SCE's liability insurance levels and cost. On September 1, 2009, SCE renewed its insurance coverage, which included coverage for wildfire liabilities up to a reduced limit of $500 million (with an increased self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up the insurance coverage could result in substantially higher self-insured costs in the event of multiple wildfire occurrences during the policy period (September 1, 2009 to August 31, 2010). SCE may experience further coverage reductions and/or increased insurance costs in future years. SCE and the other California investor-owned utilities have filed a joint application with the CPUC seeking recovery of uninsured losses and increased insurance costs. SCE cannot predict the outcome of this proceeding or when a decision will be issued by the CPUC.

LIQUIDITY

Overview

As of September 30, 2009, SCE had approximately $3.5 billion of available liquidity comprised of cash and equivalents and short-term investments and $2.8 billion available under credit facilities. The following table summarizes the status of SCE's credit facilities at September 30, 2009:

In millions	Credit Facilities(1)
Commitment	$	2,894
Outstanding borrowings		—
Outstanding letters of credit		(82	)
Amount available	$	2,812

(1)

SCE has two credit facilities with various banks. In June 2009, SCE amended the $2.5 billion five-year credit facility to remove a subsidiary of Lehman Brothers Holdings as a lender which resulted in a reduction of the total commitment under the facility to $2.4 billion. The five-year credit facility matures February 2013, with four extension options which, if all exercised, and agreed to by the lenders, will result in a final termination in February 2017. In March 2009, SCE entered into a new $500 million 364-day revolving credit facility terminating on March 16, 2010. SCE expects to use the additional liquidity provided by the facility to address potential requirements of SCE's ongoing procurement-related needs.

As of September 30, 2009, SCE's long-term debt, including current maturities of long-term debt, was $6.7 billion. In March 2009, SCE issued $500 million of 6.05% first and refunding mortgage bonds due in 2039 and $250 million of 4.15% first and refunding mortgage bonds due in 2014. The bond proceeds were used for general corporate purposes and to finance fuel inventories.

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SCE's estimated cash outflows during the 12-month period following September 30, 2009 are expected to consist of:

•

Projected capital expenditures primarily to replace and expand distribution and transmission infrastructure and construct and replace major components of generation assets (see "—Capital Expenditures" below);

•

Fuel and procurement-related costs (see "Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings" in the year-ended 2008 MD&A), including collateral requirements (see "—Margin and Collateral Deposits");

•

In December 2008, June 2009 and September 2009, the Board of Directors of SCE declared $100 million dividends to Edison International which were paid in January 2009, July 2009 and October 2009, respectively. Additional dividends by SCE are dependent upon several factors including the actual level of capital expenditures, operating cash flows and earnings;

•

Principal and interest payments on short- and long-term debt outstanding;

•

General operating expenses; and

•

Pension and PBOP trust contributions.

SCE expects to meet its 2009 continuing obligations, including cash outflows for operating expenses and power-procurement, as well as projected 2009 capital expenditures through cash and equivalents on hand, and operating cash flows. SCE expects that it would also be able to draw on the remaining availability of its credit facilities and access capital markets if additional funding and liquidity is necessary to meet the estimated operating and capital requirements.

SCE's liquidity may be affected by matters described in "Regulatory Matters" and "Commitments and Indemnities."

American Recovery and Reinvestment Act of 2009

The American Recovery and Reinvestment Act of 2009 extended the 50% bonus depreciation provision for an additional year to include property placed in service by December 31, 2009. SCE expects that certain capital expenditures incurred during 2009 will qualify for this accelerated bonus depreciation, which would provide additional 2009 cash flow benefits estimated to be in the range of approximately $125 million to $175 million.

Repair Deductions

During the third quarter of 2009, the IRS granted companies permission to automatically elect to change their tax accounting method for routine repair and maintenance costs. The change in method would result in the recognition of a cumulative catch-up deduction in 2009 for certain repair costs that were previously capitalized and depreciated over the tax depreciable life of the property. In the fourth quarter of 2009, Edison International expects to file an election to change its tax accounting method for certain repair costs incurred mainly on SCE's transmission and distribution infrastructure assets. Unless there is further IRS guidance which may impact Edison International's ability to make such election, SCE expects to reflect the initial impact in its estimated fourth quarter 2009 federal income tax payment. SCE has not completed its detailed analysis and cannot determine the impact on its results of operations and cash flows at this time.

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Intercompany Tax-Allocation Agreement

SCE is included in the consolidated federal and combined state income tax returns of Edison International and participates in tax-allocation payments with other subsidiaries of Edison International in accordance with the terms of intercompany tax allocation agreements among the affiliated companies.

In connection with the Global Settlement, Edison International made federal and state tax payments of approximately $195 million. Under the tax allocation agreement, Edison International made net tax allocation payments of approximately $875 million to SCE.

SCE expects that the Global Settlement will result in a positive cash impact over time. The following table provides the approximate cash flow expected over time:

In millions
Taxes settled through September 30, 2009	$	875
Estimated future net tax payments		(235	)
Cash flow expected over time	$	640

See "Management Overview—Global Settlement" for further discussion on the Global Settlement.

Capital Expenditures

SCE's updated capital investment plan projects total capital expenditures for the period 2009 – 2013 to be in the range of $16.8 billion to $19.8 billion. The capital investment plan has been updated primarily to reflect timing changes due to slower than anticipated permitting and licensing of some major transmission projects. The 2009 – 2011 planned capital expenditures for CPUC-jurisdictional projects are consistent with the revenue requirements authorized in SCE's 2009 GRC. Recovery of planned capital expenditures for CPUC-jurisdictional projects beyond 2011 is subject to the outcome of future CPUC general rate cases or other CPUC approvals. Recovery of certain projects included in the 2009 – 2013 capital investment plan have been approved or will be requested through other CPUC-authorized mechanisms on a project-by-project basis. These projects include, among others, SCE's Solar Photovoltaic Program (based on the decision discussed below) and SCE's EdisonSmartConnect™ project. Recovery of 2009 planned capital expenditures for FERC-jurisdictional projects was approved in SCE's 2009 Rate Case (see "Regulatory Matters—Current Regulatory Developments—2009 FERC Rate Case" above for further information). Recovery of planned capital expenditures for FERC-jurisdictional projects beyond 2009 is subject to future FERC approval.

Execution of SCE's capital investment plan is dependent on access to capital markets, regulatory decisions, and economic conditions in the U.S and SCE's service territory. The completion of the projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, weather and other unforeseen conditions.

SCE capital expenditures (including accruals) related to its 2009 capital plan were $1.9 billion for the first nine months of 2009. SCE's capital expenditures for the first nine months of 2009 were approximately 20% less than forecast, primarily due to timing delays resulting from a later than expected 2009 GRC decision. As discussed above, the revised capital expenditure forecast for 2009 – 2013 was updated to address expected permitting delays of major transmission projects and as a result, SCE assumed 15% variability to the current forecast (compared to 18% in 2008) in its estimated range of capital expenditures over the next five years: 2009 – $2.6 billion to $3.1 billion; 2010 – $3.3 billion to $3.8 billion;

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2011 – $3.6 billion to $4.2 billion; 2012 – $3.8 billion to $4.5 billion; and 2013 – $3.5 billion to $4.2 billion. The estimated capital expenditures for the next five years may vary from SCE's current forecast.

Credit Ratings

SCE's credit ratings are as follows:

	Moody's Rating		S&P Rating		Fitch Rating
Long-term senior secured debt		A1		A		A+
Short-term (commercial paper)		P-2		A-2		F-1

On July 2 and July 13, 2009, Fitch and S&P affirmed SCE's credit ratings, respectively. In addition, on July 8, 2009, Moody's issued a credit opinion with no change to its previously issued credit ratings for SCE. Subsequently, on August 3, 2009, Moody's upgraded most senior secured ratings of investment-grade regulated utilities by one notch. As a result, SCE's long-term senior secured debt was upgraded to A1 from A2. SCE cannot provide assurance that its current credit ratings will remain in effect for any given period of time or that one or more of these ratings will not be changed. These credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

Dividend Restrictions and Debt Covenants

The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At September 30, 2009, SCE's 13-month weighted-average common equity component of total capitalization was 49.5% resulting in the capacity to pay $212 million in additional dividends.

SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At September 30, 2009, SCE's debt to total capitalization ratio was 0.45 to 1.

Margin and Collateral Deposits

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. Collateral requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments, and other factors. Future collateral requirements may be higher (or lower) than requirements at September 30, 2009, due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, and the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations.

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. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the liability or post additional collateral. The

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table below illustrates the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of September 30, 2009.

In millions
Collateral posted as of September 30, 2009(1)	$	98
Incremental collateral requirements resulting from a potential downgrade of SCE's credit rating to below investment grade		240
Total posted and potential collateral requirements(2)	$	338

(1)

Collateral posted consisted of $1 million which was offset against derivative liabilities in accordance with the authoritative accounting guidance which allows for the netting of counterparty receivables and payables under a master netting arrangement, and $97 million provided to counterparties and other brokers (consisting of $16 million in cash reflected in "Margin and collateral deposits" on the consolidated balance sheets and $81 million in letters of credit).

(2)

Total posted and potential collateral requirements may increase by an additional $51 million, based on SCE's forward position as of September 30, 2009, 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 no collateral posted as of September 30, 2009 related to derivative liabilities, and $18 million of incremental collateral requirements related to derivative liabilities.

SCE's incremental collateral requirements are expected to be met from liquidity available from cash on hand and available capacity under SCE's credit facilities, discussed above.

MARKET RISK EXPOSURES

SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. SCE uses derivative financial instruments, as appropriate, to manage its market risks.

Commodity Price Risk

Introduction

As discussed in the year-ended 2008 MD&A, SCE is exposed to commodity price risk from its purchases of capacity and ancillary services to meet peak energy requirements and from exposure to natural gas prices that affect costs associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including the Mountainview and peaker plants.

Natural Gas and Electricity Price Risk

As discussed in the year-ended 2008 MD&A, SCE has a hedging program in place to minimize ratepayer exposure to variability in market prices; however, to the extent that SCE does not mitigate the entire exposure to commodity price risk, the unhedged portion is subject to the risks and benefits of spot-market price movements, which are passed through to ratepayers.

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The following table summarizes the fair values of outstanding derivative financial instruments used at SCE to mitigate its exposure to spot market prices:

	September 30, 2009						December 31, 2008
In millions	Assets			Liabilities			Assets			Liabilities
Electricity options, swaps and forward arrangements	$	1		$	20		$	7		$	15
Natural gas options, swaps and forward arrangements		78			161			80			304
Congestion revenue rights and firm transmission rights(1)		314			—			81			—
Tolling arrangements(2)		47			564			63	��		647
Netting and collateral		(8	)		(9	)		—			(72	)
Total	$	432		$	736		$	231		$	894

(1)

In September 2007 and November 2008, the CAISO allocated CRRs for the period April 2009 through December 2017 based on SCE's load requirements. In addition, SCE participated in CAISO auctions for the procurement of additional CRRs. The CRRs meet the definition of a derivative.

(2)

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, of which five received regulatory approval in the fourth quarter of 2008 and 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 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. See "Other Developments—Environmental Matters—Priority Reserve Legal Challenges" in the year-ended 2008 MD&A.

SCE recognizes realized gains and losses on derivative instruments as purchased power expense and recovers these costs from ratepayers. Due to expected future recovery from ratepayers, unrealized gains and losses are deferred and are not recognized as purchased power expense until realized. As a result, realized and unrealized gains and losses do not affect earnings, but may temporarily affect cash flows. Realized losses on economic hedging activities were $113 million and $307 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to realized gains on economic hedging activities of $14 million and $39 million for the comparable periods in 2008, respectively. Changes in realized gains and losses on economic hedging activities were primarily due to significant decreases in settled natural gas prices. Unrealized losses on economic hedging activities were $198 million for the three months ended September 30, 2009, and unrealized gains on economic hedging activities were $428 million for the nine months ended September 30, 2009. Unrealized losses on economic hedging activities were $617 million and $131 million for the comparable periods in 2008, respectively. Changes in unrealized gains and losses on economic hedging activities were primarily related to the recognition of the long-term portion of CRRs recorded in the first quarter of 2009 as well as contracts related to SCE's new generating resources (discussed above) as compared to the three- and nine-month periods ended September 30, 2008.

Effective January 1, 2008, SCE adopted the authoritative guidance that established a hierarchy for fair value measurements. For further discussion of SCE's adoption, see "SCE Notes to Consolidated Financial Statements—Note 9. Fair Value Measurements."

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Market Redesign and Technology Upgrade

The MRTU market became effective on March 31, 2009 and SCE began participating in the day-ahead and real-time markets for the sale of its generation and purchases of its load requirements. See "Market Risk Exposures—Commodity Price Risk—Market Redesign and Technology Upgrade" in the year-ended 2008 MD&A for a further description of these markets.

Interest Rate Risk

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used for liquidity purposes, to fund business operations and to finance capital expenditures. The nature and amount of SCE's long-term and short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors. At September 30, 2009, 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 $6.7 billion.

Credit Risk

As discussed in the year-ended 2008 MD&A, as part of SCE's procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. If a counterparty were to default on its contractual obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales of excess energy and realized gains on derivative instruments.

The 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.

At September 30, 2009, the amount of balance sheet exposure as described above, broken down by the credit ratings of SCE's counterparties, was as follows:

	September 30, 2009
In millions	Exposure(2)		Collateral			Net Exposure
S&P Credit Rating(1)
A or higher	$	79	$	(4	)	$	75
A-		313		—			313
BBB+		1		—			1
BBB		—		—			—
BBB-		—		—			—
Below investment grade and not rated		—		—			—
Total	$	393	$	(4	)	$	389

(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.

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The credit risk exposure set forth in the above table is comprised of $4 million of net account receivables and $389 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

The CAISO comprises 80% of the total net exposure above and is mainly related to the CRRs' fair value (see "—Commodity Price Risk" for further information).

RESULTS OF OPERATIONS

The following subsections of "Results of Operations" and "Historical Cash Flow Analysis" provide a discussion on the changes in various line items presented on the Consolidated Statements of Income, as well as a discussion of the changes on the Consolidated Statements of Cash Flows.

SCE has contracts with certain QFs that contain variable contract provisions based on the price of natural gas. Four of these contracts are with entities that are partnerships owned in part by EME. The QFs sell electricity to SCE and steam to nonrelated parties. In accordance with authoritative accounting guidance which requires consolidation of certain variable interest entities, SCE consolidates these Big 4 projects.

Operating Revenue

The following table sets forth the major components of operating revenue:

	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2009			2008			2009			2008
Operating revenue
Retail billed and unbilled revenue	$	3,301		$	3,192		$	7,518		$	7,334
Balancing account (over)/under collections		(390	)		(103	)		(516	)		265
Sales for resale		30			141			133			466
Big 4 projects (SCE's VIEs)		47			128			153			343
Other (including intercompany transactions)		81			110			243			290
Total	$	3,069		$	3,468		$	7,531		$	8,698

SCE's retail sales represented approximately 95% and 93% of operating revenue for the three- and nine-month periods ended September 30, 2009, respectively, compared to approximately 89% and 87% for the comparable periods in 2008, respectively. 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. Of total operating revenue, approximately $1.5 billion and $3.5 billion was subject to balancing account treatment for the three- and nine-month periods ended September 30, 2009, respectively, compared to approximately $2.0 billion and $4.9 billion for the same periods in 2008, respectively.

Total operating revenue decreased by $399 million and $1.2 billion for the three- and nine-month periods ended September 30, 2009, respectively, compared to the same periods in 2008. The variances for the revenue components are as follows:

•

Retail billed and unbilled revenue increased $109 million and $184 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to the same periods in 2008. The quarter and year-to-date increases reflect a rate increase of $165 million and $467 million,

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respectively, and a sales volume decrease of $56 million and $283 million, respectively. Effective April 4, 2009, SCE's overall system average rate increased to 14.1¢ per-kWh (including 2.3¢ per-kWh related to CDWR). The sales volume decrease was due to the economic downturn as well as the impact of milder weather experienced in 2009 compared to the same periods in 2008.

•

For the three- and nine-month periods ended September 30, 2009, SCE deferred $390 million and $516 million of revenue collected above the authorized revenue requirement, respectively, compared to a deferral of $103 million for the three months ended September 30, 2008 and $265 million of revenue accrued due to collections below the authorized revenue requirement for the nine months ended September 30, 2008. SCE's revenue requirement provides recovery of pass-through costs under ratemaking mechanisms (balancing accounts) authorized by the CPUC. The revenue requirement for pass-through costs provides recovery of fuel and purchased-power expenses, demand-side management programs, nuclear decommissioning, public purpose programs, certain operation and maintenance expenses and depreciation expense related to certain projects. SCE recognizes revenue equal to actual costs incurred for pass-through costs. During the first quarter of 2009, SCE implemented the 2009 GRC which resulted in an updated revenue requirement retroactive to January 1, 2009 consistent with the CPUC authorization. The change in balancing account (over)/under collections for the periods was due to lower purchased power and fuel costs experienced during 2009 compared to the same periods in 2008 (see "—Purchased-Power Expense" and "—Fuel Expense" for further information).

•

Sales for resale represent the sale of excess energy. SCE determines whether it is economically beneficial to dispatch available generation resources for the sale of excess energy. Sales for resale revenue decreased for the three- and nine-month periods ended September 30, 2009 compared to the same periods in 2008 primarily due to lower natural gas prices and lower kWh sales due to SCE's decision not to dispatch generation resources because to do so would have not been economically beneficial. Revenue from sales for resale is refunded to customers through the ERRA balancing account and does not impact earnings.

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 $493 million and $1.39 billion for the three- and nine-month periods ended September 30, 2009, respectively, and $583 million and $1.68 billion for the three- and nine-month periods ended September 30, 2008, respectively.

Fuel Expense

	Three Months Ended September 30,				Nine Months Ended September 30,
In millions	2009		2008		2009		2008
SCE	$	97	$	173	$	276	$	480
SCE's VIEs (Big 4 projects)		80		242		257		681
Total fuel expense	$	177	$	415	$	533	$	1,161

SCE's fuel expense decreased $76 million and $204 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to the same periods in 2008. The quarter and year-to-date decreases were mainly due to decreases at the Mountainview plant of $65 million and $210 million, respectively, resulting primarily from lower natural gas costs in 2009 compared to 2008.

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SCE's VIEs fuel expense decreased $162 million and $424 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to the same periods in 2008. The decreases were mainly due to lower natural gas costs in 2009 compared to 2008.

Purchased-Power Expense

	Three Months Ended September 30,					Nine Months Ended September 30,
In millions	2009		2008			2009		2008
Cost of purchased power	$	919	$	1,347		$	1,848	$	3,092
Realized losses (gains) on economic hedging activities – net		113		(14	)		307		(39	)
Total purchased-power expense	$	1,032	$	1,333		$	2,155	$	3,053

SCE's total purchased-power expense decreased $301 million and $898 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to the same periods in 2008.

Cost of purchased power decreased $428 million and $1.2 billion for the three- and nine-month periods ended September 30, 2009, respectively, as compared to the same periods in 2008. The quarter and year-to-date decreases were due to: lower bilateral energy and QF purchases of $420 million and $1.1 billion, respectively, resulting from decreased kWh purchases and lower costs per kWh due to lower natural gas prices. The quarter variance also includes higher CAISO-related energy costs of $20 million. The year-to-date variance also includes lower firm transmission rights costs of $65 million (see "Market Risk Exposures—Commodity Price Risk—Natural Gas and Electricity Price Risk" for further information) and lower CAISO-related energy costs of $75 million.

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. Realized losses on economic hedging activities were $113 million and $307 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to realized gains on economic hedging activities of $14 million and $39 million for the comparable periods in 2008, respectively. Changes in realized gains and losses on economic hedging activities were primarily due to significant decreases in settled natural gas prices. See "Market Risk Exposures—Commodity Price Risk" for further discussion.

Other Operation and Maintenance

SCE's other operation and maintenance expense increased $81 million for the three months ended September 30, 2009, compared to the same period in 2008 mainly due to: $40 million of higher generation expenses related to San Onofre, $25 million of higher transmission and distribution maintenance costs and a $15 million increase related to the timing of outside service costs.

Depreciation, Decommissioning and Amortization Expense

SCE's depreciation, decommissioning and amortization expense increased $26 million and $47 million for the three- and nine-month periods ended September 30, 2009, compared to the same periods in 2008. The quarter and year-to date variances reflect an increase in planned capital expenditures (see "Liquidity—Capital Expenditures" for a further discussion) and an increase in capitalized software amortization costs of $10 million and $25 million respectively. The year-to-date variance was offset by a $17 million cumulative depreciation rate adjustment recorded in the second quarter of 2008.

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Other Nonoperating Income

SCE's other nonoperating income increased $49 million and $57 million for the three- and nine-month periods ended September 30, 2009, compared to the same periods in 2008 due to an increase in allowance for funds used during construction – equity. As discussed under the heading, "Regulatory Matters—Current Regulatory Developments—2009 General Rate Case Proceeding" in the year-ended 2008 MD&A, the final 2009 GRC decision granted the authority to transfer the assets and liabilities of Mountainview Power Company, LLC to SCE, which was subsequently approved by the FERC and transferred in July 2009. As a result of the transfer, SCE recognized a one time, non-cash, accounting benefit of approximately $46 million in July 2009 to recognize differences in the accounting treatment for non-regulated and rate-regulated entities mainly related to equity AFUDC.

Interest Expense – Net of Amounts Capitalized

SCE's interest expense – net of amounts capitalized increased $23 million for the nine months ended September 30, 2009 compared to the same period in 2008. The increase was primarily due to higher interest expense on long-term debt resulting from higher outstanding balances compared to the same period in 2008. This increase was partially offset by lower over-collections of certain balancing accounts and lower interest rates applied to those over-collections during 2009 compared to the same period in 2008 and lower interest expense on short-term debt resulting from lower outstanding balances compared to the same period in 2008.

Other Nonoperating Deductions

SCE's other nonoperating deductions decreased $68 million and $81 million for the three- and nine-month periods ended September 30, 2009, compared to the same periods in 2008 mainly due to approximately $60 million related to the CPUC decision on SCE's PBR mechanism in September 2008. The quarter and year-to-date variances were also due to approximately a $10 million and $30 million decrease in expenditures made related to civic, political and related activities, and donations, respectively.

Income Taxes

SCE's composite federal and state statutory income tax rates were approximately 41% and 40% (net of the federal benefit for state income taxes) for 2009 and 2008 respectively. SCE's effective tax rates, excluding income attributable to non-controlling interests, were 40% and 13% for the three- and nine-month periods ended September 30, 2009, respectively, as compared to 39% and 32% for the respective periods in 2008. The principal items affecting comparability of the effective tax rates for the three- and nine-month periods ended September 30, 2009 and 2008 were lower software and property flow-through deductions in 2009, partially offset by higher nondeductible expenses during 2008. The nine-month period also includes a $300 million benefit recorded in 2009 related to the Global Settlement.

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HISTORICAL CASH FLOW ANALYSIS

The "Historical Cash Flow Analysis" section of this MD&A discusses consolidated cash flows from operating, financing and investing activities.

Cash Flows from Operating Activities

	Nine Months Ended September 30,
In millions	2009		2008
Cash flows provided by operating activities	$	3,281	$	1,313

Cash provided by operating activities increased $2.0 billion in 2009 compared to 2008. The 2009 change was primarily due to the following:

•

The impacts of the Global Settlement which resulted in a net tax allocation payment received from Edison International of $875 million and an increase in deferred tax liabilities related to the settlement of affirmative claims (See "Management Overview—Global Settlement" for further discussion).

•

ERRA balancing account collections of approximately $480 million in 2009, compared to ERRA balancing account refunds of approximately $615 million in 2008. The ERRA balancing account was over-collected by $76 million and under-collected by $406 million at September 30, 2009 and December 31, 2008, respectively, compared to an under-collection of $182 million and an over-collection of $433 million at September 30, 2008 and December 31, 2007, respectively.

•

A net $620 million cash outflow variance related to all other regulatory balancing accounts which was primarily due to increased spending in 2009 compared to 2008 for public purpose and solar initiative programs. In addition, a $200 million refund payment was received in 2008 related to public purpose programs.

•

Higher authorized revenue requirements resulting from the implementation of the 2009 GRC decision.

•

Timing of cash receipts and disbursements related to working capital items.

Cash Flows from Financing Activities

	Nine Months Ended September 30,
In millions	2009			2008
Net cash provided (used) by financing activities	$	(1,854	)	$	1,393

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

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

•

In March 2009, SCE 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.

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•

In March 2009, SCE purchased two issues of its tax-exempt pollution control bonds totaling approximately $219 million 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.

•

In February 2009, SCE repaid $150 million of its first and refunding mortgage bonds.

•

During the first nine months of 2009, SCE's net repayments of short-term debt were $1.9 billion.

•

Other financing activities in 2009 include dividend payments of $200 million paid to Edison International.

Financing activities for the first nine months of 2008 were as follows:

•

In January 2008, SCE issued $600 million of first refunding mortgage bonds due in 2038. The proceeds were used to repay SCE's outstanding commercial paper of approximately $426 million and for general corporate purposes.

•

In January 2008, SCE repurchased 350,000 shares of 4.08% cumulative preferred stock at a price of $19.50 per share. SCE retired this preferred stock in January 2008 and recorded a $2 million gain on the cancellation of reacquired capital stock (reflected in the caption "Common stock" on the consolidated balance sheets).

•

During the first quarter of 2008, SCE purchased $212 million of its auction rate bonds, converted the issue to a variable rate structure, and terminated the FGIC insurance policy. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.

•

In August 2008, SCE issued $400 million of 5.50% first and refunding mortgage bonds due in 2018. The proceeds were used to repay SCE's outstanding commercial paper of approximately $110 million and borrowings under the credit facility of $200 million, as well as for general corporate purposes.

•

During the first nine months of 2008, SCE's net issuances of short-term debt were $1.1 billion.

•

Other financing activities in 2008 include dividend payments of $225 million paid to Edison International and payments of $28 million for the purchase and delivery of outstanding common stock for settlement of stock based awards (facilitated by a third party).

Cash Flows from Investing Activities

	Nine Months Ended September 30,
In millions	2009			2008
Net cash used by investing activities	$	(2,284	)	$	(1,702	)

Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts.

Investing activities in 2009 reflect $2.1 billion in capital expenditures, primarily for transmission and distribution assets, including approximately $80 million for nuclear fuel acquisitions and $163 million for net purchases of nuclear decommissioning trust investments.

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Investing activities in 2008 reflect $1.6 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $70 million for nuclear fuel acquisitions and $50 million for net purchases of nuclear decommissioning trust investments.

NEW ACCOUNTING REQUIREMENTS

New accounting pronouncements are discussed in Note 1—Summary of Significant Accounting Policies—New Accounting Requirements under "SCE's Notes to Consolidated Financial Statements."

COMMITMENTS AND INDEMNITIES

The following is an update to SCE's commitments and indemnities. See the section, "Commitments and Indemnities" in the year-ended 2008 MD&A for a detailed discussion.

Uncertain Tax Position Net Liability

At September 30, 2009, SCE recorded a liability for uncertain tax positions of $446 million. SCE currently cannot reliably predict the timing of cash flows associated with the resolution of uncertain tax positions due to timing of resolving tax issues with the IRS. Edison International's federal income tax returns are subject to examination by the IRS for tax years 2003 to present. Consummation of the Global Settlement effectively closed tax years 1986 - 2002 with the IRS (see "Management Overview—Global Settlement"). Edison International's California and other state income tax returns are open for tax years 1986 through 2008.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Information responding to Part I, Item 3 is included in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," under the heading "Market Risk Exposures" is incorporated herein by this reference.

Item 4.    Controls and Procedures

Disclosure Controls and Procedures

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

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.

SCE has not designed, established, or maintained internal control over financial reporting for four variable interest entities, referred to as "VIEs," that SCE was required to consolidate under an accounting interpretation issued by the Financial Accounting Standards Board. SCE's evaluation of internal control over financial reporting does not include these VIEs.

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PART II. OTHER INFORMATION

Item 6.    Exhibits

Southern California Edison Company

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 September 30, 2009, filed on November 6, 2009, 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

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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/ LINDA G. SULLIVAN     LINDA G. SULLIVAN Senior Vice President, Chief Financial Officer and Acting Controller (Duly Authorized Officer and Principal Financial and Accounting Officer)

Date: November 6, 2009

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