SOUTHERN CALIFORNIA EDISON Co - Quarter Report: 2009 June (Form 10-Q)

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

FORM 10-Q


(Mark One)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended June 30, 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 August 4, 2009

Common Stock, no par value		434,888,104

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SOUTHERN CALIFORNIA EDISON COMPANY

INDEX

			Page No.

Part I. Financial Information
	Item 1.	Financial Statements	1
		Consolidated Statements of Income – Three and Six Months Ended June 30, 2009 and 2008	1
		Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2009 and 2008	1
		Consolidated Balance Sheets – June 30, 2009 and December 31, 2008	2
		Consolidated Statements of Cash Flows – Six Months Ended June 30, 2009 and 2008	4
		Notes to Consolidated Financial Statements	5
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	53
	Item 4.	Controls and Procedures	54
Part II. Other Information
	Item 1.	Legal Proceedings	55
	Item 4.	Submission of Matters to a Vote of Security Holders	56
	Item 6.	Exhibits	57
Signature			58

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GLOSSARY

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


AB		Assembly Bill
AFUDC		allowance for funds used during construction
APS		Arizona Public Service Company
ARO(s)		asset retirement obligation(s)
Bcf		billion cubic feet
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CARB		Clean Air Resources Board
CDWR		California Department of Water Resources
CEC		California Energy Commission
CPSD		Consumer Protection and Safety Division
CPUC		California Public Utilities Commission
CRRs		congestion revenue rights
DOE		United States Department of Energy
DPV2		Devers-Palo Verde 2
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
FSP		FASB Staff Position
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

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GLOSSARY (Continued)


ISO		California Independent System Operator
kWh(s)		kilowatt-hour(s)
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
NO_x		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
SAB		Staff Accounting Bulletin
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
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS No. 133		Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
SFAS No. 157		Statement of Financial Accounting Standards No. 157, Fair Value Measurements
SFAS No. 158		Statement of Financial Accounting Standards No. 158, Employers' Accounting for Defined Benefit Pension and Other Post-Retirement Plans
SFAS No. 160		Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements

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GLOSSARY (Continued)


SFAS No. 161		Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133
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)

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SOUTHERN CALIFORNIA EDISON COMPANY

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended June 30,						Six Months Ended June 30,


In millions	2009			2008			2009			2008

	(Unaudited)
Operating revenue	$	2,273		$	2,850		$	4,462		$	5,231

Fuel		156			397			356			746
Purchased power		583			1,026			1,124			1,721
Other operation and maintenance		762			760			1,420			1,426
Depreciation, decommissioning and amortization		289			287			574			553
Property and other taxes		61			56			127			118
Gain on sale of assets		(1	)		(7	)		(1	)		(8	)

Total operating expenses		1,850			2,519			3,600			4,556

Operating income		423			331			862			675
Interest income		2			5			6			10
Other nonoperating income		29			25			56			44
Interest expense – net of amounts capitalized		(106	)		(96	)		(215	)		(193	)
Other nonoperating deductions		(12	)		(14	)		(20	)		(26	)

Income before income taxes		336			251			689			510
Income tax expense (benefit)		(198	)		30			(77	)		111

Net income		534			221			766			399
Less: Net income attributable to noncontrolling interests		22			51			34			67
Dividends on preferred and preference stock not subject to mandatory redemption		13			13			25			25

Net income available for common stock	$	499		$	157		$	707		$	307

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

			Three Months Ended June 30,				Six Months Ended June 30,


In millions			2009		2008		2009		2008

			(Unaudited)
Net income			$	534	$	221	$	766	$	399
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		(1	)

Comprehensive income				535		221		767		398
Less: Comprehensive income attributable to noncontrolling interests				22		51		34		67

Comprehensive income attributable to Southern California Edison			$	513	$	170	$	733	$	331

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

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SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

In millions		June 30, 2009			December 31, 2008


		(Unaudited)
ASSETS
Cash and equivalents		$	454		$	1,611
Short-term investments			3			3
Receivables, less allowances of $41 and $39 for uncollectible accounts at respective dates			706			703
Accrued unbilled revenue			505			328
Inventory			325			365
Derivative assets			154			157
Regulatory assets			334			605
Deferred income taxes – net			—			147
Other current assets			125			283

Total current assets			2,606			4,202

Nonutility property – less accumulated depreciation of $798 and $765 at respective dates			910			953
Nuclear decommissioning trusts			2,673			2,524
Other investments			84			68

Total investments and other assets			3,667			3,545

Utility plant, at original cost:
	Transmission and distribution		20,863			20,006
	Generation		1,900			1,819
Accumulated depreciation			(5,573	)		(5,570	)
Construction work in progress			2,308			2,454
Nuclear fuel, at amortized cost			273			260

Total utility plant			19,771			18,969

Derivative assets			467			74
Regulatory assets			4,852			5,414
Other long-term assets			457			364

Total long-term assets			5,776			5,852

Total assets		$	31,820		$	32,568

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

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SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

In millions, except share amounts	June 30, 2009			December 31, 2008


	(Unaudited)
LIABILITIES AND EQUITY
Short-term debt	$	—		$	1,893
Long-term debt due within one year		250			150
Accounts payable		753			948
Accrued taxes		63			340
Accrued interest		184			153
Customer deposits		239			227
Book overdrafts		177			224
Derivative liabilities		133			156
Regulatory liabilities		948			1,111
Deferred income taxes – net		90			—
Other current liabilities		483			572

Total current liabilities		3,320			5,774

Long-term debt		6,489			6,212

Deferred income taxes – net		3,249			2,918
Deferred investment tax credits		99			101
Customer advances		126			137
Derivative liabilities		524			738
Pensions and benefits		2,570			2,485
Asset retirement obligations		3,091			3,007
Regulatory liabilities		2,635			2,481
Other deferred credits and other long-term liabilities		1,303			902

Total deferred credits and other liabilities		13,597			12,769

Total liabilities		23,406			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		540			532
Accumulated other comprehensive loss		(13	)		(14	)
Retained earnings		4,430			3,827

Total common shareholder's equity		7,125			6,513
Preferred and preference stock not subject to mandatory redemption		920			920
Noncontrolling interests		369			380

Total equity		8,414			7,813

Total liabilities and equity	$	31,820		$	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 COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Six Months Ended June 30,


In millions		2009			2008

		(Unaudited)
Cash flows from operating activities:
Net income		$	766		$	399
Adjustments to reconcile to net cash provided by operating activities:
	Depreciation, decommissioning and amortization		574			553
	Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)		86			57
	Other amortization		55			47
	Stock-based compensation		6			8
	Deferred income taxes and investment tax credits		447			6
	Long-term regulatory assets and liabilities – net		654			184
	Long-term derivative assets and liabilities – net		(606	)		(184	)
	Other assets		(106	)		(19	)
	Other liabilities		446			28
Changes in working capital:
	Receivables and accrued unbilled revenue		(162	)		(244	)
	Inventory		40			(26	)
	Other current assets		158			(15	)
	Book overdrafts		(47	)		86
	Accrued taxes		(277	)		4
	Accounts payable and other current liabilities		(67	)		88
	Current regulatory assets and liabilities – net		107			197
	Current derivative assets and liabilities – net		(20	)		(380	)

Net cash provided by operating activities			2,054			789

Cash flows from financing activities:
Long-term debt issued			750			600
Long-term debt issuance costs			(11	)		(9	)
Long-term debt repaid			(151	)		(1	)
Bonds repurchased			(219	)		(212	)
Preferred stock redeemed			—			(7	)
Short-term debt financing – net			(1,893	)		300
Stock-based compensation – net			—			(8	)
Distributions to noncontrolling interests			(45	)		(65	)
Dividends paid			(125	)		(150	)

Net cash provided (used) by financing activities			(1,694	)		448

Cash flows from investing activities:
Capital expenditures			(1,402	)		(1,241	)
Proceeds from nuclear decommissioning trust sales			1,310			1,501
Purchases of nuclear decommissioning trust investments and other			(1,415	)		(1,560	)
Sales of short-term investments			1			—
Purchases of short-term investments			(1	)		(2	)
Customer advances for construction and other investments			(10	)		(2	)

Net cash used by investing activities			(1,517	)		(1,304	)

Net decrease in cash and equivalents			(1,157	)		(67	)
Cash and equivalents, beginning of period			1,611			252

Cash and equivalents, end of period		$	454		$	185

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 six months ended June 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 filed with the Securities and Exchange Commission.

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 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 adoption of SFAS No. 160 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 August 7, 2009, the date the financial statements were issued.

Cash Equivalents

Cash equivalents included money market funds totaling $326 million and $1.49 billion at June 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 9. Additionally, cash and equivalents of $81 million and $89 million at June 30, 2009 and December 31, 2008, respectively are included 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 energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the positions. In accordance with FIN No. 39-1, "Amendment of FASB Interpretation No. 39," SCE presents a portion of its margin and cash collateral deposits net with its derivative

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positions on its consolidated balance sheets. Amounts recognized for cash collateral provided to others that have been offset against derivative liabilities totaled $67 million and $72 million at June 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral provided to others that have not been offset against derivative liabilities totaled $33 million and $17 million at June 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral received from others that have not been offset against derivative assets totaled $7 million and $8 million at June 30, 2009 and December 31, 2008, respectively.

New Accounting Pronouncements

In May 2009, the FASB issued SFAS No. 165, "Subsequent Events." SFAS No. 165 sets forth the period after 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 SFAS No. 165, effective April 1, 2009. The adoption of this standard had no impact on SCE's consolidated results of operations, financial position or cash flows.

In April 2009, the FASB issued FSP SFAS No. 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions that Are Not Orderly." FSP SFAS No. 157-4 affirms 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. FSP SFAS No. 157-4 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, FSP SFAS No. 157-4 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 position and to quantify its effects, if practicable. This position also requires disclosures on a more disaggregated basis for investments in debt and equity securities measured at fair value. SCE adopted FSP SFAS No. 157-4, effective April 1, 2009. The adoption of this position did not have an impact on SCE's consolidated results of operations, financial position or cash flows.

In April 2009, the FASB issued FSP SFAS No. 115-2 and SFAS 124-2, "Recognition and Presentation of Other-Than-Temporary Impairments." This position amends existing guidance for determining whether impairment is other than temporary for debt securities. Under this position, 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 position, effective April 1, 2009, resulting in increased disclosures. The adoption of this position did not have an impact on SCE's consolidated results of operations, financial position or cash flows. See Note 9.

In April 2009, the FASB issued FSP SFAS No. 107-1 and APB No. 28-1, "Interim Disclosures about Fair Value of Financial Instruments." This position requires 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 position, effective April 1, 2009. Since FSP SFAS No. 107-1 and APB No. 28-1 impacts disclosure only, the adoption of this position did not have an impact on SCE's consolidated results of operations, financial position or cash flows. See Note 9.

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Effective January 1, 2009, SCE adopted SFAS No. 157 for nonrecurring fair value measurements of nonfinancial assets and liabilities. The adoption of SFAS No. 157 for nonrecurring fair value measurements did not have a material impact on SCE's consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, which requires 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 statement 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 pronouncement effective January 1, 2009 and retrospectively applied this standard as of December 31, 2008. In accordance with this standard, 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.

In March 2008, the FASB issued SFAS No. 161, which requires 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 pronouncement effective January 1, 2009. Since SFAS No. 161 impacts disclosures only, the adoption of this standard 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 Pronouncements Not Yet Adopted

In December 2008, the FASB issued FSP FAS 132(R)-1, "Employers' Disclosures about Postretirement Benefit Plan Assets." This position requires additional plan asset disclosures 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 significant unobservable inputs (Level 3) and significant concentrations of risk. This position is effective for years ending after December 15, 2009 and, therefore, SCE will adopt FSP FAS 132(R)-1 at year-end 2009. FSP FAS 132(R)-1 will impact disclosures only and will not have an impact on SCE's consolidated results of operations, financial position or cash flows.

In June 2009, the FASB issued SFAS No. 167, "Amendments to FASB Interpretation No. 46(R)." SFAS No. 167 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 will adopt SFAS No. 167 on January 1, 2010 and is currently evaluating the impact, if any, that the adoption of this standard will have on its consolidated financial statements.

In June 2009, the FASB issued SFAS No. 168, "The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles." This Statement establishes the Codification to become 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 Statement, 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

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change U.S. GAAP or guidance issued by the SEC. However, Codification will affect the way SCE researches accounting issues and references U.S. GAAP in its notes to consolidated financial statements and MD&A. SCE will adopt this Statement in the third quarter of 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.

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 SCE's 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 SCE's Mountainview and peaker plants, approximately 44% 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		23,058
Natural gas options, swaps and forward arrangements	Bcf		296
Congestion revenue rights⁽¹⁾	MW		503,017
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. The CRRs meet the definition of a derivative under SFAS No. 133.
(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 June 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	$	155		$	467	$	622		$	201		$	524	$	725		$	103
Netting and collateral			(1	)		—		(1	)		(68	)		—		(68	)		(67	)

Total		$	154		$	467	$	621		$	133		$	524	$	657		$	36

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 $96 million and $194 million for the three- and six-month periods ended June 30, 2009, respectively, compared to realized gains on economic hedging activities of $28 million and $26 million for the comparable periods in 2008, respectively. Unrealized gains on economic hedging activities were

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$293 million and $626 million for the three- and six-month periods ended June 30, 2009, respectively, compared to $333 million and $486 million for the comparable periods in 2008, respectively.

Contingent Features/Credit Related Exposure

Certain derivative instruments under SCE's power and natural gas trading activities contain margin and collateral requirements. SCE has historically provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses and unrealized gains in connection with derivative activities. 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 margin and collateral requirements 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 June 30, 2009, was $82 million, for which SCE has posted collateral of less than $1 million to its counterparties. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2009, SCE would be required to post an additional $32 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 Holding 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 June 30, 2009:

In millions	(Unaudited)


Commitment	$	2,894
Less: Outstanding letters of credit		(88	)

Amount available	$	2,806

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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. The effective tax rate was (63)% and (12)% for the three-and six-month periods ended June 30, 2009, respectively, as compared to 15% and 25% for the respective periods in 2008. The 2009 effective tax rate was lower when compared to both the 2008 effective tax rate and the 2009 statutory rate mainly due to a $300 million benefit related primarily to tax timing differences on certain affirmative claims as a result of 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 for 1 year the 50% bonus depreciation provision to eligible property placed in service prior to January 1, 2010, provided for an option to claim cash grants in lieu of investment tax credits, including the solar energy investment tax credit. Cash grants would be obtained separately from the tax return under rules and regulations published by the U. S. Treasury Department. SCE anticipates utilizing the solar energy investment tax credit for its investment in its PV Solar Rooftop facilities. SCE will review this plan based on the rules and regulations regarding the grant payments in lieu of tax credits recently issued by the U. S. Treasury Department and based on tax planning activities during the second part of 2009. 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 December 31 to June 30 for 2009 and 2008:

In millions			2009			2008


			(Unaudited)
Balance at beginning of period			$	2,066		$	1,950
	Tax positions taken during the current year
		Increases		28			53
		Decreases		—			—
	Tax positions taken during a prior year
		Increases		138			85
		Decreases		(25	)		(97	)
	Decreases for settlements during the period			(1,741	)		—
	Reductions for lapses of applicable statute of limitations			—			—

Balance at June 30			$	466		$	1,991

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.

Edison International 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 June 30, 2009 and December 31, 2008, respectively, if recognized, $73 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 $61 million and $120 million as of June 30, 2009 and December 31, 2008, respectively. After-tax interest income recognized in income tax expense, was $292 million and $289 million for the three- and six-month periods ended June 30, 2009, respectively, and after-tax interest expense recognized in income tax expense was $3 million and $9 million for the three- and six-month periods ended June 30, 2008, respectively.

Tax Years Subject to Examination

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, discussed below, effectively closed the examination for tax years 1986 - 2002. In addition to the IRS audits, Edison International's California and other state income tax returns are open for examination by the California Franchise Tax Board and the other state tax authorities for tax years 1986 to present. 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 $300 million reflected in "Income tax expense (benefit)" on the consolidated statements of income primarily related to settlement of two affirmative claims associated with the taxation of balancing account overcollections and taxation of proceeds received in consideration for transferring control of SCE's transmission and distribution system to the ISO 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 receipt of 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

As of June 30, 2009, SCE has made no contributions related to 2008 and $25 million related to 2009 and estimates to make $14 million of additional contributions in the last six months of 2009.

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 June 30,						Six Months Ended June 30,


In millions	2009			2008			2009			2008

	(Unaudited)
Service cost	$	27		$	27		$	54		$	54
Interest cost		48			46			96			93
Expected return on plan assets		(40	)		(63	)		(80	)		(126	)
Amortization of prior service cost		4			4			8			8
Amortization of net (gain)/loss		13			—			26			(1	)

Subtotal	$	52		$	14		$	104		$	28
Regulatory adjustment – deferred		(37	)		—			(74	)		—

Total expense recognized	$	15		$	14		$	30		$	28

Postretirement Benefits Other Than Pensions

As of June 30, 2009, SCE has made no contributions related to 2008 and $9 million related to 2009 and estimates to make $117 million of additional contributions in the last six months of 2009.

Expense components are:

	Three Months Ended June 30,						Six Months Ended June 30,


In millions	2009			2008			2009			2008

	(Unaudited)
Service cost	$	10		$	11		$	20		$	22
Interest cost		34			33			68			66
Expected return on plan assets		(21	)		(31	)		(42	)		(62	)
Amortization of prior service credit		(7	)		(7	)		(14	)		(14	)
Amortization of net loss		15			4			30			8

Total expense recognized	$	31		$	10		$	62		$	20

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 $5 million for the three months ended June 30, 2009 and 2008, respectively, and was $9 million and $10 million for the six months ended June 30, 2009 and 2008, respectively. The income tax benefit recognized in the consolidated statements of income was $2 million for both the three months ended June 30, 2009 and 2008 and was $4 million for both the six months ended June 30, 2009 and 2008. Total stock-based compensation cost capitalized was $1 million and $2 million for the three- and six-month periods ended June 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		2,783,741		$	24.86
Expired		(13,752	)	$	32.03
Forfeited		(147,384	)	$	32.23
Exercised		(141,196	)	$	22.98
Transfer to associate		(36,981	)	$	35.62

Outstanding at June 30, 2009		8,845,162		$	31.79		6.97

Vested and expected to vest at June 30, 2009		8,444,200		$	31.74		6.87	$	36,333,950

Exercisable at June 30, 2009		4,715,122		$	30.67		5.24	$	23,462,704

The amount of cash used to settle stock options exercised was $1 million and $10 million for the three months ended June 30, 2009 and 2008, respectively, and was $5 million and $19 million for the six months ended June 30, 2009 and 2008, respectively. Cash received from options exercised was $1 million and $5 million for the three months ended June 30, 2009 and 2008, respectively, and was $3 million and $9 million for the six months ended June 30, 2009 and 2008, respectively. The estimated tax benefit from options exercised was less than $1 million and $2 million for the three months ended June 30, 2009 and 2008, respectively, and was $1 million and $4 million for the six months ended June 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		99,194		$	20.14
Forfeited		(7,410	)	$	29.05
Transferred to associate		(624	)	$	57.99
Paid out		—		$	—

Nonvested at June 30, 2009		169,677		$	36.85

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

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"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		99,194
Forfeited		(7,410	)
Transferred to associate		(624	)
Paid out		—

Nonvested at June 30, 2009		169,677		$	22.41

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 June 30, 2009 and December 31, 2008. The asset carrying amount, net of amortization, was $15 million and $16 million at June 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 and 2011. There are no sublease rentals and the contingent rentals for capital leases were less than $1 million for both the six months ended June 30, 2009 and 2008, respectively. 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	Power Contracts Operating Leases		Other Operating Leases		Capital Leases


	(Unaudited)
Year ending December 31,
2009 (remaining six months)	$	435	$	29	$	3
2010		626		53		37
2011		498		46		120
2012		361		39		120
2013		356		34		120
Thereafter		2,186		111		2,526

Total future commitments	$	4,462	$	312	$	2,926
Amount representing executory costs		—		—		(710	)
Amount representing interest		—		—		(994	)

Net commitments	$	4,462	$	312	$	1,222

Operating lease expense was $77 million and $83 million for the three months ended June 30, 2009 and 2008, respectively, and was $135 million and $142 million for the six months ended June 30, 2009 and 2008, respectively.

Other Commitments

During the second quarter of 2009, SCE extended its power purchase agreement with Midway Sunset which resulted in additional commitments estimated to be: remainder of 2009 – $13 million, 2010 – $18 million, 2011 – $18 million, 2012 – $18 million, 2013 – $18 million and thereafter – $129 million. See Note 11 for additional information related to the terms of the extended agreement.

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

Mountainview owns and operates a power plant in Redlands, California. The 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

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associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this guarantee.

Other Indemnities

SCE provides other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and specified environmental indemnities and income taxes with respect to assets sold. SCE's obligations under these agreements may be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties for certain indemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overall maximum amount of the obligation under these indemnifications cannot be reasonably estimated. SCE has not recorded a liability related to these indemnities.

Contingencies

In addition to the matters disclosed in these Notes, SCE is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. SCE believes 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 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 future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that additional costs would be recovered from customers or that SCE's financial position and results of operations 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 June 30, 2009, SCE's recorded estimated minimum liability to remediate its 24 identified sites was $39 million, of which $6 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

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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 $39 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

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

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $11 million to $30 million. Recorded costs were $2 million and $7 million for the three months ended June 30, 2009 and 2008, respectively, and $5 million and $10 million for the six months ended June 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 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.

Federal and State Income Taxes

Edison International remains subject to examination by the IRS for tax years 2003 to present. As discussed in the section "Global Settlement" in Note 4, the Global Settlement was finalized on May 5, 2009 and effectively closed the examination for tax years 1986 – 2002.

2009 FERC Rate Case

On March 1, 2009, SCE implemented, subject to refund, proposed revisions to its base transmission rates initially accepted by the FERC. SCE and the parties to the FERC rate case reached a settlement on the 2009 base transmission rates and on July 1, 2009, SCE filed the proposed settlement. The settlement provides for a revenue requirement of $448 million, which increases SCE's revenue requirement by $136 million over the previously authorized base transmission revenue requirement. SCE expects that the FERC will issue an order approving the proposed settlement during the third quarter of 2009. If approved by the FERC, the proposed settlement rates will become retroactively effective as of March 1, 2009. As of June 30, 2009, SCE had collected revenue, subject to refund, of $21 million that, upon final approval of the settlement agreement, will be refunded to ratepayers. SCE did not recognize this refund in revenue and implementation of the settlement agreement will not impact earnings.

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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 DPV2 and Tehachapi transmission projects and 75 basis points for SCE's Rancho Vista Substation Project ("Rancho Vista"), as well as a 50 basis points 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 DPV2 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 at the DC Circuit Court of Appeals but the appeal has been deferred until a final FERC order is issued in the 2008 CWIP case.

FERC Construction Work in Progress Mechanism (CWIP)

2008 CWIP

In February 2008, the FERC approved, subject to refund, SCE's revision to its tariff to collect 100% of CWIP in rate base for its Tehachapi, DPV2, and Rancho Vista projects, as authorized by FERC in its transmission incentives order discussed above which resulted in base transmission revenue billed of $37 million. In March 2008, the CPUC filed a petition for 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 an evidentiary 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.

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 $43 million, of which approximately $10 million had been expended through June 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.

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ISO Disputed Charges

The FERC issued an order that has been subject to continuing legal proceedings concerning a dispute between the ISO and the cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. On July 16, 2009, the FERC issued an order, subject to appeal, denying a request for rehearing made by the cities and reaffirmed its previous decision that certain transmission service related charges should be allocated to the cities. The cities have 60 days to file an appeal. If a subsequent regulatory decision changes the allocation of responsibility for these charges and SCE is required to pay these charges as a transmission owner, estimated to be a net amount of approximately $20 million to $25 million, including interest, SCE may seek recovery in its reliability service rates. SCE cannot predict either the outcome of any appeal or whether recovery of these charges in its reliability service rates would be permitted in rates if SCE is required to pay these charges.

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.

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

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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.

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 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.

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Note 7. Consolidated Statement of Changes in Equity

The following table provides changes in equity for the six months ended June 30, 2009:

	Equity Attributable to SCE

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

	(Unaudited)
Balance at December 31, 2008	$	2,168	$	532	$	(14	)	$	3,827		$	920	$	380		$	7,813
Net income		—		—		—			732			—		34			766
Other comprehensive income		—		—		1			—			—		—			1
Dividends declared on common stock		—		—		—			(100	)		—		—			(100	)
Dividends declared on preferred and preference stock not subject to mandatory redemption		—		—		—			(25	)		—		—			(25	)
Distributions to noncontrolling interests		—		—		—			—			—		(45	)		(45	)
Shares purchased for stock-based compensation		—		—		—			(5	)		—		—			(5	)
Proceeds from stock option exercises		—		—		—			3			—		—			3
Noncash stock-based compensation and other		—		6		—			(2	)		—		—			4
Excess tax benefits related to stock-based awards		—		2		—			—			—		—			2

Balance at June 30, 2009	$	2,168	$	540	$	(13	)	$	4,430		$	920	$	369		$	8,414

The following table provides changes in equity for the six months ended June 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		—		—		—			332			—			67			399
Other comprehensive loss		—		—		(1	)		—			—			—			(1	)
Dividends declared on common stock		—		—		—			(200	)		—			—			(200	)
Dividends declared on preferred and preference stock not subject to mandatory redemption		—		—		—			(25	)		—			—			(25	)
Preferred stock redeemed, net of gain		—		2		—			—			(9	)		—			(7	)
Distributions to noncontrolling interests		—		—		—			—			—			(65	)		(65	)
Shares purchased for stock-based compensation		—		—		—			(25	)		—			—			(25	)
Proceeds from stock option exercises		—		—		—			9			—			—			9
Noncash stock-based compensation and other		—		8		—			(4	)		—			—			4
Excess tax benefits related to stock-based awards		—		8		—			—			—			—			8

Balance at June 30, 2008	$	2,168	$	525	$	(16	)	$	3,655		$	920		$	448		$	7,700

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Note 8. Supplemental Cash Flows Information

SCE's supplemental cash flows information is:

		Six Months Ended June 30,


In millions		2009			2008

		(Unaudited)
Cash payments for interest and taxes:
Interest – net of amounts capitalized		$	170		$	139
Tax payments (receipts)		$	(868	)	$	46
Noncash investing and financing activities:
Dividends declared but not paid:
	Common stock	$	100		$	100
	Preferred and preference stock not subject to mandatory redemption	$	13		$	13

Note 9. Fair Value Measurements

SFAS No. 157 defines fair value 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" in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability should reflect the entity's non-performance risk. In addition, SFAS No. 157 establishes a fair value hierarchy 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 under SFAS No. 157 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 June 30, 2009, SCE reduced the fair value of derivative assets and derivative liabilities for nonperformance risks by $4 million and $16 million, respectively.

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 June 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⁾		$	326	$	—		$	—		$	—		$	326
	Derivative contracts			2		1			619			(1	)		621
	Long-term disability plan			10		—			—			—			10
	Nuclear decommissioning trusts⁽³⁾
		Municipal bonds		—		618			—			—			618
		Stocks		1,435		—			—			—			1,435
		United States government issues		178		30			—			—			208
		Corporate bonds		—		378			—			—			378
		Short-term investments, primarily cash equivalents		2		19			—			—			21

		Sub-total of nuclear decommissioning trusts	$	1,615	$	1,045		$	—		$	—		$	2,660

Total assets⁽⁴⁾			$	1,953	$	1,046		$	619		$	(1	)	$	3,617
Liabilities at Fair Value
	Derivative contracts			—		(223	)		(502	)		68			(657	)

Net assets (liabilities)			$	1,953	$	823		$	117		$	67		$	2,960

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⁾		$	1,486		$	—		$	—		$	—	$	1,486
	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⁾			$	2,979		$	1,046		$	227		$	—	$	4,252
Liabilities at Fair Value
	Derivative contracts			(2	)		(219	)		(745	)		72		(894	)

Net assets (liabilities)			$	2,977		$	827		$	(518	)	$	72	$	3,358

(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 $13 million and $(4) million at June 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 June 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 June 30,					Six Months Ended June 30,


In millions		2009			2008		2009			2008

		(Unaudited)
Fair value, net at beginning of period		$	(126	)	$	79	$	(518	)	$	(22	)
Total realized/unrealized gains (losses):
	Included in earnings		—			—		—			—
	Included in regulatory assets and liabilities⁽¹⁾		204			112		591			165
	Included in accumulated other comprehensive income		—			—		—			—
Purchases and settlements, net			39			74		44			122
Transfers in or out of Level 3			—			—		—			—

Fair value, net at June 30		$	117		$	265	$	117		$	265

Change during the period in unrealized gains related to financial instruments held at June 30		$	212		$	149	$	604		$	176

(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:

In millions	Maturity Dates	June 30, 2009		December 31, 2008		June 30, 2009		December 31, 2008

		Amortized Cost				Fair Value


		(Unaudited)
Municipal bonds	2009 – 2042	$	548	$	561	$	618	$	629
Stocks	–		818		839		1,435		1,308
United States government issues	2009 – 2051		191		268		208		304
Corporate bonds	2009 – 2049		316		214		378		260
Short-term investments, primarily cash equivalents	2009		34		24		34		23

Total		$	1,907	$	1,906	$	2,673	$	2,524

Note: Maturity dates as of June 30, 2009.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Realized gains were $115 million and $25 million for the three months ended June 30, 2009 and 2008, respectively and $189 million and $53 million for the six months ended June 30, 2009 and 2008, respectively. Realized losses were $77 million and $5 million for the three months ended June 30, 2009 and 2008, respectively and $140 million and $6 million for the six months ended June 30, 2009 and 2008, respectively. Proceeds from sales of securities (which are reinvested) were $652 million and $672 million for the three months ended June 30, 2009 and 2008, respectively and $1.3 billion and $1.5 billion for the six months ended June 30, 2009 and 2008, respectively.

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Unrealized holding gains, net of losses, were $766 million and $618 million at June 30, 2009 and December 31, 2009, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible.

The following table sets forth a summary of changes in the fair value of the trust for the six months ended June 30, 2009:

In millions	2009


	(Unaudited)
Balance at beginning of period	$	2,524
Realized gains – net		49
Unrealized gains – net		148
Other-than-temporary impairments		(103	)
Interest, dividends, contributions and other		55

Balance at June 30, 2009	$	2,673

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 each month compared to 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 realized 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 every three years by the CPUC. These contributions are determined based on an analysis of the current value of trusts assets and 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 in a 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:

	June 30, 2009				December 31, 2008


In millions	Carrying Amount		Fair Value		Carrying Amount		Fair Value

	(Unaudited)
Long-term debt	$	6,489	$	6,847	$	6,212	$	6,566
Long-term debt due within one year	$	250	$	265	$	150	$	151

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

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Note 10. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

In millions	June 30, 2009		December 31, 2008


	(Unaudited)
Current:
Regulatory balancing accounts	$	214	$	455
Energy derivatives		120		138
Other		—		12

	$	334	$	605

Long-term:
Regulatory balancing accounts	$	35	$	29
Flow-through taxes – net		1,456		1,337
ARO		171		224
Unamortized nuclear investment – net		360		375
Nuclear-related ARO investment – net		268		278
Unamortized coal plant investment – net		77		79
Unamortized loss on reacquired debt		298		309
SFAS No. 158 pensions and postretirement benefits		1,898		1,882
Energy derivatives		111		723
Environmental remediation		39		40
Other		139		138

	$	4,852	$	5,414

Total Regulatory Assets	$	5,186	$	6,019

Regulatory liabilities included on the consolidated balance sheets are:

In millions	June 30, 2009		December 31, 2008


	(Unaudited)
Current:
Regulatory balancing accounts	$	940	$	1,068
Other		8		43

	$	948	$	1,111

Long-term:
Regulatory balancing accounts	$	34	$	43
Costs of removal		2,456		2,368
Employee benefit plans		145		70

	$	2,635	$	2,481

Total Regulatory Liabilities	$	3,583	$	3,592

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Note 11. 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. These four contracts had 20-year terms at inception. The QFs sell electricity to SCE and steam to nonrelated parties. Under FIN 46(R), SCE consolidates these four 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


	(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.

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 effect SCE's income statement, except that SCE would be required to recognize losses if these projects have negative equity in the future. These losses, if any, would not affect SCE's liquidity. Any liabilities of these projects are nonrecourse to SCE. See Note 12 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 under FIN 46(R). SCE might be considered to be the consolidating entity under this standard. SCE continues to attempt to obtain information for these projects in order to determine whether the projects should be consolidated by SCE. These entities are not legally obligated to provide the financial information to SCE and have declined to provide any financial information to SCE. Under the grandfather scope provisions of FIN 46(R), SCE is not required to apply this rule 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 June 30, 2009 and December 31, 2008, respectively. The amounts that SCE paid to these projects were $30 million and $57 million for the three months ended June 30, 2009 and 2008, respectively, and $60 million and $98 million for the six months ended June 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 12. 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 June 30, 2009:
Cash and equivalents	$	373	$	81	$	—		$	454
Accounts receivable – net		687		60		(41	)		706
Inventory		305		20		—			325
Other current assets		125		—		—			125
Nonutility property – net of depreciation		644		266		—			910
Other long-term assets		456		1		—			457
Total assets	$	31,433	$	428	$	(41	)	$	31,820
Accounts payable	$	752	$	42	$	(41	)	$	753
Other current liabilities		482		1		—			483
Asset retirement obligations		3,075		16		—			3,091
Noncontrolling interests		—		369		—			369
Total liabilities and equity	$	31,433	$	428	$	(41	)	$	31,820

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 June 30, 2009:
Operating revenue	$	2,227		$	131		$	(85	)	$	2,273
Fuel		80			76			—			156
Purchased power		668			—			(85	)		583
Other operation and maintenance		737			25			—			762
Depreciation, decommissioning and amortization		281			8			—			289
Property and other taxes		61			—			—			61
Gain on sale of assets		(1	)		—			—			(1	)
Total operating expenses		1,826			109			(85	)		1,850
Operating income		401			22			—			423
Interest income		2			—			—			2
Other nonoperating income		29			—			—			29
Interest expense – net of amounts capitalized		(106	)		—			—			(106	)
Other nonoperating deductions		(12	)		—			—			(12	)
Income tax benefit		198	⁽²⁾		—			—			198
Net income		512			22			—			534
Net income attributable to noncontrolling interest		—			(22	)		—			(22	)
Dividends on preferred and preference stock not subject to mandatory redemption		(13	)		—			—			(13	)
Net income available for common stock	$	499		$	—		$	—		$	499
Income Statement Items for the Three Months Ended June 30, 2008:
Operating revenue	$	2,733		$	326		$	(209	)	$	2,850
Fuel		149			248			—			397
Purchased power		1,235			—			(209	)		1,026
Other operation and maintenance		738			22			—			760
Depreciation, decommissioning and amortization		279			8			—			287
Property and other taxes		56			—			—			56
Gain on sale of assets		(7	)		—			—			(7	)
Total operating expenses		2,450			278			(209	)		2,519
Operating income		283			48			—			331
Interest income		4			1			—			5
Other nonoperating income		23			2			—			25
Interest expense – net of amounts capitalized		(96	)		—			—			(96	)
Other nonoperating deductions		(14	)		—			—			(14	)
Income tax expense		(30	)		—			—			(30	)
Net income		170			51			—			221
Net income attributable to noncontrolling interest		—			(51	)		—			(51	)
Dividends on preferred and preference stock not subject to mandatory redemption		(13	)		—			—			(13	)
Net income available for common stock	$	157		$	—		$	—		$	157

(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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In millions	Electric Utility			VIEs			Eliminations⁽¹⁾			SCE


	(Unaudited)
Income Statement Items for the Six Months Ended June 30, 2009:
Operating revenue	$	4,356		$	274		$	(168	)	$	4,462
Fuel		179			177			—			356
Purchased power		1,292			—			(168	)		1,124
Other operation and maintenance		1,374			46			—			1,420
Depreciation, decommissioning and amortization		557			17			—			574
Property and other taxes		127			—			—			127
Gain on sale of assets		(1	)		—			—			(1	)
Total operating expenses		3,528			240			(168	)		3,600
Operating income		828			34			—			862
Interest income		6			—			—			6
Other nonoperating income		56			—			—			56
Interest expense – net of amounts capitalized		(215	)		—			—			(215	)
Other nonoperating deductions		(20	)		—			—			(20	)
Income tax benefit		77	⁽²⁾		—			—			77
Net income		732			34			—			766
Net income attributable to noncontrolling interest		—			(34	)		—			(34	)
Dividends on preferred and preference stock not subject to mandatory redemption		(25	)		—			—			(25	)
Net income available for common stock	$	707		$	—		$	—		$	707
Income Statement Items for the Six Months Ended June 30, 2008:
Operating revenue	$	5,016		$	575		$	(360	)		5,231
Fuel		306			440			—			746
Purchased power		2,081			—			(360	)		1,721
Other operation and maintenance		1,371			55			—			1,426
Depreciation, decommissioning and amortization		536			17			—			553
Property and other taxes		118			—			—			118
Gain on sale of assets		(8	)		—			—			(8	)
Total operating expenses		4,404			512			(360	)		4,556
Operating income		612			63			—			675
Interest income		8			2			—			10
Other nonoperating income		42			2			—			44
Interest expense – net of amounts capitalized		(193	)		—			—			(193	)
Other nonoperating deductions		(26	)		—			—			(26	)
Income tax expense		(111	)		—			—			(111	)
Net income		332			67			—			399
Net income attributable to noncontrolling interest		—			(67	)		—			(67	)
Dividends on preferred and preference stock not subject to mandatory redemption		(25	)		—			—			(25	)
Net income available for common stock	$	307		$	—		$	—		$	307

(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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Note 13. Subsequent Events

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 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 $705 million and $173 million, respectively. In addition, SCE recognized a one time, non-cash, accounting gain of approximately $46 million 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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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

This MD&A for the three- and six-month periods ended June 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 six month periods ended June 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, filed with the Securities and Exchange Commission.

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, particularly in light of current credit conditions in the capital markets;
•: 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 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;
•: market risks affecting SCE's energy procurement activities;
•: 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;

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•: 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;
•: effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
•: the outcome of disputes with the IRS and other 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; and
•: the risks inherent in the development of generation projects as well as transmission and distribution infrastructure replacement and expansion including those related to siting, financing, construction, permitting, and governmental approvals.

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 is presented in 7 major sections: (1) management overview; (2) liquidity; (3) regulatory matters; (4) other developments; (5) market risk exposures; (6) results of operations and historical cash flow analysis; and (7) new accounting pronouncements.

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MANAGEMENT OVERVIEW

Areas of Business Focus

Federal and State Income Taxes

Global Settlement

Business Development and Capital Commitments

SCE's growth strategy includes improving reliability and expanding the capability of its distribution and transmission infrastructure, constructing and replacing generation assets, and deploying advanced metering infrastructure. SCE continues to implement its growth strategy and revised its 2009 – 2013 capital investment plan to be consistent with the revenue requirements authorized in its 2009 GRC final decision, as well as other CPUC and FERC proceedings. SCE's significant planned projects are as follows:

Transmission and Distribution Projects

•: Devers-Palo Verde 2 – A transmission project that, as modified, would install a high voltage (500 kV) transmission line from Romoland, California east to Blythe, California. SCE continues its efforts to obtain the regulatory approvals necessary to construct the DPV2 project. The California portion of the project is currently expected to be placed in service in 2013, subject to licensing and regulatory approvals. Over the period 2009 – 2013, SCE expects to spend $718 million for the project (excluding the previously proposed Arizona portion of the project). As originally proposed, the project would have continued the transmission line from Romoland to a new substation near Palo Verde, west of Phoenix, Arizona. However, the line will now terminate at the Colorado River switch yard east of Blythe rather than continuing into Arizona as originally proposed. SCE is continuing to evaluate its transmission needs in western Arizona, but does not currently intend to seek regulatory approval for the Arizona portion of the project. If SCE and the relevant regulatory agencies determine that construction of the Arizona portion is in the interest of California ratepayers, SCE will seek regulatory approvals for the appropriate transmission facilities in western Arizona at that time.
•: 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.

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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 2013, subject to receipt of licensing and regulatory approvals. SCE expects to spend $2.1 billion over the period 2009 – 2013 on this project.

•: Rancho Vista Substation Project – A new 500 kV substation in the City of Rancho Cucamonga was completed and placed in service in May 2009. The total construction cost of the project from inception to completion was approximately $200 million.
•: Other capital investments consisting of $3.4 billion for transmission development and $9.7 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 $457 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. SCE expects to spend $790 million over the period 2009 – 2013. See "Liquidity—Capital Expenditures—Solar Photovoltaic Program" for further discussion.

Other Projects

•: EdisonSmartConnect™ – SCE's advanced metering project that will install state-of-the-art "smart" meters in approximately 5.3 million households and small businesses throughout its service territory. SCE expects to begin 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.

SCE's 2009 – 2013 revised total capital investment plan includes capital spending in the range of $16.8 billion to $20.4 billion. See "Liquidity—Capital Expenditures" for further discussion.

Environmental Developments

Climate Change Legislation

On June 26, 2009, the American Clean Energy and Security Act was passed by the U.S. House of Representatives. The bill would establish a 20% mandatory federal combined efficiency and renewable electricity standard for retail electricity suppliers like SCE and establish a cap-and-trade system for carbon emissions commencing in 2012. Under the cap-and-trade system, a cap to reduce aggregate greenhouse gas emissions from all covered entities would be established and decline over time. Emitters of greenhouse gases would be required to have allowances for greenhouse gas emissions emitted during a relevant measurement period. The bill would provide for stated portions of required allowances to be allocated (including allocation to merchant generators) free of charge in declining amounts over time. Emitters of greenhouse gases 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

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(for alternative greenhouse gas conservation efforts). Legislation to regulate greenhouse gas emissions is now being considered by the U.S. Senate, and the timing, content, and the potential effects on SCE of climate change legislation, if any, that may be ultimately passed by the Congress and signed into law by the President remain uncertain.

Earnings Performance

SCE's earnings from continuing operations were $499 million and $707 million for the three- and six-month periods ended June 30, 2009, respectively, compared to $157 million and $307 million for the respective periods in 2008. SCE's quarter and year-to-date earnings related primarily to tax timing differences on certain affirmative claims in 2009 include the impact of the Global Settlement which resulted in after-tax earnings of $300 million (see "—Areas of Business Focus—Federal and State Income Taxes" for further discussion). The quarter and year-to-date increases also reflect higher operating income associated with the 2009 GRC decision and lower operating expense mainly due to timing differences.

REGULATORY MATTERS

Current Regulatory Developments

This section of the MD&A describes significant regulatory issues that may impact SCE's financial condition or results of operations.

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 has slightly revised its capital expenditure forecasts for the period 2009 – 2013. See "Liquidity—Capital Expenditures" for further discussion.

As discussed under the heading, "Regulatory Matters—Current Regulatory Developments—2009 General Rate Case Proceeding" in the year-ended 2008 MD&A, the final decision also 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 gain 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.

FERC Rate Cases

2009

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SCE expects that the FERC will issue an order approving the proposed settlement during the third quarter of 2009. If approved by the FERC, the proposed settlement rates will become retroactively effective as of March 1, 2009. As of June 30, 2009, SCE had collected revenue, subject to refund, of $21 million that, upon final approval of the settlement agreement, will be refunded to ratepayers. SCE did not recognize this refund in revenue and implementation of the settlement agreement will not impact earnings.

2010

On July 31, 2009, SCE filed proposed revisions to the 2009 base transmission rates (discussed above), which would increase SCE's revenue requirement by $107 million, or 24%, over the 2009 base transmission revenue requirement and requested an effective date of October 1, 2009. This proposed revenue requirement results in an approximate 1% increase to SCE's overall system average rate. The proposed increase is primarily due to an increase in transmission rate base, mainly associated with transmission projects already in service or expected to enter service in 2009 and 2010.

Cost of Capital Mechanism

As discussed in the year-ended 2008 MD&A, the CPUC determines SCE's cost of capital in a multi-year proceeding occurring every three years, with a provision that allows for a potential adjustment between the cost of capital filings if certain thresholds are reached. Under the current mechanism, the existing capital structure and authorized rate of return will remain in place through December 2010, absent any potential annual adjustment. The mechanism would be subject to CPUC review in 2010 for the cost of capital set for 2011 and beyond.

SCE expects to file with the CPUC a petition to modify the current mechanism that would forgo an expected 2010 cost of capital increase under the annual adjustment provision and extend SCE's current capital structure and authorized rate of return through 2012, subject to future potential adjustments. Absent CPUC approval of SCE's petition, SCE's next potential adjustment will be submitted to the CPUC in October 2009, effective for 2010.

OTHER DEVELOPMENTS

Environmental Matters

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 is now in the process of providing requested information to the US EPA according to a schedule that was agreed upon with the US EPA. 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.

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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 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.

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." SCE is currently reviewing the draft policy.

Environmental Remediation

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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.

LIQUIDITY

Overview

As of June 30, 2009, SCE had $3.26 billion of available liquidity made up of $457 million of cash and equivalents and short-term investments ($81 million of which was held by SCE's consolidated VIEs), as well as $2.8 billion remaining under credit facilities. The following table summarizes the status of SCE's credit facilities at June 30, 2009:

In millions	Credit Facilities⁽¹⁾


Commitment	$	2,894
Outstanding borrowings		—
Outstanding letters of credit		(88	)

Amount available	$	2,806

(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 Holding as a lender which resulted in a reduction of the total commitment under the facility to $2.4 billion. In March 2008, SCE amended the five-year credit facility, extending the maturity to February 2013. The March 2008 amendment also provides four extension options which, if all exercised, and agreed to by 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

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the additional liquidity provided by the facility to address potential requirements of SCE's ongoing procurement-related needs.

As of June 30, 2009, SCE's long-term debt, including current maturities of long-term debt, was $6.74 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.

SCE's estimated cash outflows during the 12-month period following June 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 and June 2009 the Board of Directors of SCE declared two $100 million dividends to Edison International which were paid in January 2009 and July 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.

As discussed above, SCE expects to meet its 2009 continuing obligations, including cash outflows for operating expenses and power-procurement, through cash and equivalents on hand, and operating cash flows. Projected 2009 capital expenditures are expected to be financed through cash and equivalents on hand, operating cash flows and incremental capital market financings. 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, but given uncertain market conditions there can be no assurance of capital market availability.

On February 17, 2009, President Obama signed the American Recovery and Reinvestment Act of 2009 which extended the availability of accelerated bonus depreciation through the end of 2009. Edison International expects that certain capital expenditures incurred by SCE 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.

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

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

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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 $195 million. Under the tax allocation agreement, Edison International made net tax allocation payments of $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 amount expected:

In millions


Taxes settled through June 30, 2009	$	875
Estimated future net tax payments		(235	)

Cash flow expected over time	$	640

See "Other Developments—Federal and State Income Taxes" for further discussion on the Global Settlement.

Capital Expenditures

SCE's capital investment plan projects total capital expenditures for the period 2009 – 2013 to be in the range of $16.8 billion to $20.4 billion. 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 is subject to FERC approval in SCE's pending 2009 Rate Case (see "Regulatory Matters—Current Regulatory Developments—FERC Rate Cases" 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. 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 $1.15 billion for the first six months of 2009. SCE's capital expenditures for the first six months of 2009 were approximately 22% less than forecast, primarily due to timing delays including the delay in the 2009 GRC decision. The estimated capital expenditures for the next five years may vary from SCE's current forecast. If SCE assumes the same level of variability to forecast experienced in 2008 (approximately 18%), the estimated capital expenditures for the next five years would vary in the range of: 2009 – $2.7 billion to $3.3 billion; 2010 – $3.2 billion to $3.9 billion; 2011 – $3.5 billion to $4.3 billion; 2012 – $3.7 billion to $4.5 billion; and 2013 – $3.6 billion to $4.4 billion.

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Solar Photovoltaic Program

In June 2009, the CPUC issued a final decision approving SCE's 250 MW Solar Photovoltaic Program, which allows recovery of costs through rates provided the costs are reasonable. The final decision provided that SCE would earn its CPUC-authorized rate of return on this investment. 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.

Credit Ratings

SCE's credit ratings are as follows:




Long-term senior secured debt	A1	A	A+
Short-term (commercial paper)	P-2	A-2	F-1

On July 2, 2009 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 June 30, 2009, SCE's 13-month weighted-average common equity component of total capitalization was 49.6% resulting in the capacity to pay $225 million in additional dividends.

SCE has a debt covenant in its credit facility that requires a debt to total capitalization ratio of less than or equal to 0.65 to 1 to be met. At June 30, 2009, SCE's debt to total capitalization ratio was 0.46 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 June 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.

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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 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 June 30, 2009.

In millions


Collateral posted as of June 30, 2009⁽¹⁾	$	188
Incremental collateral requirements resulting from a potential downgrade of SCE's credit rating to below investment grade		220

Total posted and potential collateral requirements⁽²⁾	$	408

(1): Collateral posted consisted of $67 million which was offset against derivative liabilities in accordance with the implementation of FIN 39-1, and $121 million provided to counterparties and other brokers (consisting of $33 million in cash reflected in "Margin and collateral deposits" on the consolidated balance sheets and $88 million in letters of credit).
(2): Total posted and potential collateral requirements may increase by an additional $59 million, based on SCE's forward position as of June 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 less than $1 million of collateral posted as of June 30, 2009 related to derivative liabilities, and $32 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 SCE's Mountainview and peaker plants.

Natural Gas and Electricity Price Risk

As discussed in the year-ended 2008 MD&A, 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.

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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:

	June 30, 2009						December 31, 2008


In millions	Assets			Liabilities			Assets		Liabilities

Electricity options, swaps and forward arrangements	$	11		$	27		$	7	$	15
Natural gas options, swaps and forward arrangements		70			280			80		304
Congestion revenue rights and firm transmission rights⁽¹⁾		455			—			81		—
Tolling arrangements⁽²⁾		86			418			63		647
Netting and collateral		(1	)		(68	)		—		(72	)

Total	$	621		$	657		$	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 under SFAS No. 133.
(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 $96 million and $194 million for the three- and six-month periods ended June 30, 2009, respectively, compared to realized gains on economic hedging activities of $28 million and $26 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 gains on economic hedging activities were $293 million and $626 million for the three- and six-month periods ended June 30, 2009, respectively, compared to $333 million and $486 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 decreases in forward natural gas prices in 2009 compared to 2008.

SCE adopted SFAS No. 157 effective January 1, 2008. The standard established a hierarchy for fair value measurements. For further discussion of SCE's adoption of SFAS No. 157, 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 June 30, 2009, the fair market value of SCE's long-term debt (including long-term debt due within one year) was $7.1 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 June 30, 2009, the amount of balance sheet exposure as described above, broken down by the credit ratings of SCE's counterparties, was as follows:

	June 30, 2009

In millions	Exposure⁽²⁾		Collateral			Net Exposure

S&P Credit Rating⁽¹⁾
A or higher	$	89	$	(4	)	$	85
A-		456		—			456
BBB+		1		—			1
BBB		—		—			—
BBB-		—		—			—
Below investment grade and not rated		1		(2	)		(1	)

Total	$	547	$	(6	)	$	541

(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 $543 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

Due to recent developments in the financial markets, the credit ratings may not be reflective of the related credit risk. The CAISO comprises 84% 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 AND HISTORICAL CASH FLOW ANALYSIS

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. As required by FIN 46(R), SCE consolidates these Big 4 projects.

Operating Revenue

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

	Three Months Ended June 30,					Six Months Ended June 30,


In millions	2009			2008		2009			2008

Operating revenue
Retail billed and unbilled revenue	$	2,322		$	2,244	$	4,217		$	4,143
Balancing account (over)/under collections		(189	)		257		(126	)		368
Sales for resale		13			143		104			325
Big 4 projects (SCE's VIEs)		46			118		106			215
Other (including intercompany transactions)		81			88		161			180

Total	$	2,273		$	2,850	$	4,462		$	5,231

SCE's retail sales represented approximately 94% and 92% of operating revenue for the three- and six-month periods ended June 30, 2009, respectively, compared to approximately 88% and 86% 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 $1.0 billion and $2.0 billion was subject to balancing account treatment for the three- and six-month periods ended June 30, 2009, respectively, compared to approximately $1.7 billion and $2.9 billion for the same periods in 2008, respectively.

Total operating revenue decreased by $577 million and $769 million for the three- and six-month periods ended June 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 $78 million and $74 million for the three- and six-month periods ended June 30, 2009, respectively, compared to the same periods in 2008. The quarter and year-to-date increases reflect a rate increase of $216 million and $287 million, respectively, and a sales volume decrease of $138 million and $213 million, respectively. Effective April 4, 2009, SCE's

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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 downtown as well as the impact of milder weather experienced in the later part of second quarter 2009 compared to the same period in 2008.

•: For the three- and six-month periods ended June 30, 2009, SCE deferred $189 million and $126 million of revenue collected above the authorized revenue requirement, respectively, compared to $257 million and $368 million of revenue accrued due to collections below the authorized revenue requirement for the three- and six-month periods ended June 30, 2008, respectively. 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 six-month periods ended June 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 $391 million and $896 million for the three- and six-month periods ended June 30, 2009, respectively and $539 million and $1.1 billion for the three- and six-month periods ended June 30, 2008, respectively.

Fuel Expense

	Three Months Ended June 30,				Six Months Ended June 30,


In millions	2009		2008		2009		2008

SCE	$	80	$	149	$	179	$	306
SCE's VIEs (Big 4 projects)		76		248		177		440

Total fuel expense	$	156	$	397	$	356	$	746

SCE's fuel expense decreased $69 million and $127 million for the three- and six-month periods ended June 30, 2009, respectively, compared to the same periods in 2008. The quarter and year-to-date decreases were mainly due to decreases at SCE's Mountainview plant of $80 million and $145 million, respectively, resulting primarily from lower natural gas costs in 2009 compared to 2008.

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SCE's VIEs fuel expense decreased $172 million and $263 million for the three- and six-month periods ended June 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 June 30,					Six Months Ended June 30,


In millions	2009		2008			2009		2008

Cost of purchased power	$	487	$	1,054		$	930	$	1,747
Realized losses (gains) on economic hedging activities – net		96		(28	)		194		(26	)

Total purchased-power expense	$	583	$	1,026		$	1,124	$	1,721

SCE's total purchased-power expense decreased $443 million and $597 million for the three- and six-month periods ended June 30, 2009, respectively, compared to the same periods in 2008.

Cost of purchased power decreased $567 million and $817 million for the three- and six-month periods ended June 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 $475 million and $640 million, respectively, resulting from decreased kWh purchases and lower costs per kWh due to lower natural gas prices; and lower ISO-related energy costs of $90 million and $100 million, respectively. The year-to-date variance also includes lower firm transmission rights costs of $60 million (see "Market Risk Exposures—Natural Gas and Electricity Price Risk" for further information).

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 $96 million and $194 million for the three- and six-month periods ended June 30, 2009, respectively, compared to realized gains on economic hedging activities of $28 million and $26 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.

Depreciation, Decommissioning and Amortization Expense

SCE's depreciation, decommissioning and amortization expense increased $2 million and $21 million for the three- and six-month periods ended June 30, 2009, compared to the same periods in 2008. The quarter and year-to date variances reflect an increase in capitalized software amortization costs of $10 million and $20 million respectively. The quarter variance also reflects an increase in planned capital expenditures offset by a $17 million cumulative depreciation rate adjustment recorded in the second quarter of 2008.

Other Nonoperating Income

SCE's other nonoperating income increased $12 million for the six months ended June 30, 2009, compared to the same period in 2008 mainly due to an increase in allowance for funds used during construction—equity resulting from an increase in construction work in progress due to planned capital expenditures (see "Liquidity—Capital Expenditures" for further discussion).

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Interest Expense – Net of Amounts Capitalized

SCE's interest expense – net of amounts capitalized increased $10 million and $22 million for the three- and six-month periods ended June 30, 2009, respectively, compared to the same periods in 2008. The increases were primarily due to higher interest expense on long-term debt resulting from higher outstanding balances compared to the same periods in 2008. These increases were 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 periods in 2008.

Income Taxes

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

Cash provided by operating activities increased $1.3 billion in 2009 compared to 2008. The 2009 change was primarily due to 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—Areas of Business Focus—Federal and State Income Taxes" for further discussion). The 2009 change was also due to a net $225 million cash inflow related to balancing account activities mainly due to: ERRA balancing account collections in 2009, compared to ERRA balancing account refunds in 2008; partially offset by $200 million in refund payments received in 2008 related to SCE's public purpose programs with no comparable refunds in 2009; and a net under-collection of other balancing accounts in 2009, compared to a net over-collection in 2008. The ERRA balancing account was under-collected by $184 million and $406 million at June 30, 2009 and December 31, 2008, respectively, compared to an under-collection of $95 million and an over-collection of $433 million at June 30, 2008 and December 31, 2007, respectively. The 2009 change was also attributable to the timing of cash receipts and disbursements related to working capital items.

Cash Flows from Financing Activities

Net cash provided (used) by financing activities is as follows:

	Six Months Ended June 30,

In millions	2009			2008

Continuing operations	$	(1,694	)	$	448

Total	$	(1,694	)	$	448

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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 six 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.
•: 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 six months of 2009, SCE's net repayments of short-term debt were $1.9 billion.
•: Other financing activities in 2009 include dividend payments of $100 million paid to Edison International.

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

•: In January, 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, 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.
•: During the first six months of 2008, SCE's net issuances of commercial paper classified as short-term debt was $300 million.
•: Other financing activities in 2008 include dividend payments of $125 million paid to Edison International and payments of $25 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

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

Investing activities in 2009 reflect $1.4 billion in capital expenditures, primarily for transmission and distribution assets, including approximately $52 million for nuclear fuel acquisitions. Investing activities also include net purchases of nuclear decommissioning trust investments and other of $105 million.

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Investing activities in 2008 reflect $1.2 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $55 million for nuclear fuel acquisitions. Investing activities also include net purchases of nuclear decommissioning trust investments and other of $59 million.

NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements are discussed in Note 1—Summary of Significant Accounting Policies—New Accounting Pronouncements 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.

Other Commitments

Uncertain Tax Position Net Liability

At June 30, 2009, SCE recorded a liability for uncertain tax positions of $434 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 the examination for tax years 1986 – 2002 (see "Management Overview—Areas of Business Focus—Federal and State Income Taxes"). In addition to the IRS audits, 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 to present.

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.

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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 1. Legal Proceedings

Catalina South Coast Air Quality Management District Potential Environmental Proceeding

During the first half of 2006, the South Coast Air Quality Management District (SCAQMD) issued three NOVs alleging that Unit 15, SCE's primary diesel generation unit on Catalina Island, had exceeded the NO_x emission limit dictated by its air permit. Prior to the NOVs, SCE had filed an application with the SCAQMD seeking a permit amendment that would allow a three-hour averaging of the NO_x limit during normal (non-startup) operations and clarification regarding a startup exemption. In July 2006, the SCAQMD denied SCE's application to amend the Unit 15 air permit, and informed SCE that several conditions would have to be satisfied prior to re-application. SCE is currently in the process of developing and supplying the information and analyses required by those conditions.

On October 2, 2006 and July 19, 2007, SCE received two additional NOVs pertaining to two other Catalina Island diesel generation units, Unit 7 and Unit 10, alleging that these units have exceeded their annual NO_x limit in 2004 (Unit 10), 2005 (Unit 7), and 2006 (Unit 10). Going forward, SCE expects that the new Continuous Emissions Monitoring System, installed in late 2006, which monitors the emissions from these units, along with the employment of best practices, would enable these units to meet their annual NO_x limits in 2007.

In July 2008, SCE received an additional NOV for emitting NO_x in excess of SCE's Regional Clean Air Incentives Market (RECLAIM) credits. Under the RECLAIM program, a RECLAIM-regulated facility must have sufficient RECLAIM Trading Credits to equal the amount of NO_x that the facility emits. The NOV alleges that SCE did not have sufficient RECLAIM Trading Credits in the first and second quarters of 2007 to match the actual NO_x emissions at Catalina's generating units.

A settlement agreement, which resolves all of the NOVs, was fully executed in April 2009 and requires SCE to install new equipment by December 31, 2011 or pay a $3 million fine if the equipment is not installed by that date. The settlement agreement also provides that if SCE's application for a permit amendment is not granted, the parties will not be bound by the terms of the settlement. SCE continues to work with the SCAQMD on the permit amendment process.

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Item 4. Submission of Matters to a Vote of Security Holders

At SCE's Annual Meeting of Shareholders on April 23, 2009, two matters were put to a vote of the shareholders: the election of twelve directors and ratification of the appointment of the independent public accounting firm.

Shareholders elected twelve nominees to the Board of Directors. The number of broker non-votes for each nominee was zero. The number of votes cast for and withheld from each Director-nominee were as follows:

	Number of Votes


Name	For		Withheld

Vanessa C.L. Chang		458,057,752		1,846,182
France A. Córdova		458,000,380		1,903,554
Theodore F. Craver, Jr.		458,045,470		1,858,464
Charles B. Curtis		458,003,380		1,900,554
Alan J. Fohrer		458,051,152		1,852,782
Bradford M. Freeman		457,968,064		1,935,870
Luis G. Nogales		457,830,340		2,073,594
Ronald L. Olson		455,370,724		4,533,210
James M. Rosser		457,964,164		1,939,770
Richard T. Schlosberg, III		457,939,030		1,964,904
Thomas C. Sutton		457,788,682		2,115,252
Brett White		457,948,678		1,955,256

The proposal to ratify the appointment of the independent public accounting firm, which received the affirmative vote of a majority of the votes cast, was adopted. The proposal received the following numbers of votes:

For


459,225,730	540,108	138,096	0

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Item 6. Exhibits

Southern California Edison Company


	10.1*		Edison International Executive Incentive Compensation Plan, as amended in February 2009 (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2009)
	10.2*		Edison International Director Compensation Schedule, as adopted June 18, 2009 (File No. 1-9936, filed as Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended June 30, 2009)
	10.3*		Edison International 2007 Performance Incentive Plan, as amended and restated in February 2009 (File No. 1-9936, filed as Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended June 30, 2009)
	31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
	31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
	32		Statement Pursuant to 18 U.S.C. Section 1350
	101		Financial statements from the quarterly report on Form 10-Q of Southern California Edison Company for the quarter ended June 30, 2009, filed on August 7, 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; (v) the Notes to Consolidated Financial Statements tagged as blocks of text

*: Incorporated by reference pursuant to Rule 12b-32.

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SIGNATURE

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


	SOUTHERN CALIFORNIA EDISON COMPANY
	(Registrant)
	By		/s/ 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: August 7, 2009