SOUTHERN CALIFORNIA EDISON Co - Quarter Report: 2007 June (Form 10-Q)

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2007

¨	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 x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ¨ Accelerated Filer ¨ Non-Accelerated Filer x

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

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 3, 2007
Common Stock, no par value		434,888,104

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, 2007 and 2006	1

		Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2007 and 2006	1

		Consolidated Balance Sheets – June 30, 2007 and December 31, 2006	2

		Consolidated Statements of Cash Flows – Six Months Ended June 30, 2007 and 2006	4

		Notes to Consolidated Financial Statements	5

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44

	Item 4.	Controls and Procedures	44

Part II. Other Information

	Item 4.	Submission of Matters to a Vote of Security Holders	45

	Item 6.	Exhibits	45

	Signature		46

GLOSSARY

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


CDWR		California Department of Water Resources

CPSD		Consumer Protection and Safety Division

CPUC		California Public Utilities Commission

District Court		U.S. District Court for the District of Columbia

DOE		United States Department of Energy

DWP		Los Angeles Department of Water & Power

DRA		CPUC Division of Ratepayer Advocates

EME		Edison Mission Energy

ERRA		energy resource recovery account

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

FIN 39-1		Financial Accounting Standards Board Staff Position No. 39-1, “Amendment of FASB Interpretation No. 39”

FIN 48		Financial Accounting Standards Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FAS 109

FTR		firm transmission rights

GRC		General Rate Case

IRS		Internal Revenue Service

ISO		California Independent System Operator

kWh(s)		kilowatt-hour(s)

MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations

Midway-Sunset		Midway-Sunset Cogeneration Company

Mohave		Mohave Generating Station

MW		megawatts

Ninth Circuit		United States Court of Appeals for the Ninth Circuit

NOI		Notice of Intent

NRC		Nuclear Regulatory Commission

Palo Verde		Palo Verde Nuclear Generating Station

PBR		performance-based ratemaking

PG&E		Pacific Gas & Electric Company

PX		California Power Exchange

QF(s)		qualifying facility(ies)

San Onofre		San Onofre Nuclear Generating Station

SCE		Southern California Edison Company



SDG&E		San Diego Gas & Electric

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. 159		Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Liabilities, including an Amendment of FASB Statement No. 115”

VIE(s)		variable interest entity(ies)

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	2007		2006		2007		2006
	(Unaudited)
Operating revenue	$ 2,460		$ 2,521		$ 4,682		$ 4,739
Fuel	285		237		595		548
Purchased power	829		769		1,146		1,783
Provisions for regulatory adjustment clauses – net	(33	)	(10	)	255		(371	)
Other operation and maintenance	661		639		1,262		1,254
Depreciation, decommissioning and amortization	271		300		546		552
Property and other taxes	55		51		110		105
Net gain on sale of utility property and plant	—		(1	)	—		(1	)
Total operating expenses	2,068		1,985		3,914		3,870
Operating income	392		536		768		869
Interest income	10		15		21		30
Other nonoperating income	25		19		41		46
Interest expense – net of amounts capitalized	(105	)	(102	)	(213	)	(199	)
Other nonoperating deductions	(13	)	(9	)	(23	)	(21	)
Income before tax and minority interest	309		459		594		725
Income tax expense	61		145		114		228
Minority interest	91		67		129		117
Net income	157		247		351		380
Dividends on preferred and preference stock not subject to mandatory redemption	13		13		26		25
Net income available for common stock	$ 144		$ 234		$ 325		$ 355

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2007		2006		2007		2006
	(Unaudited)
Net income	$ 157		$ 247		$ 351		$ 380
Other comprehensive income, net of tax:
Amortization of cash flow hedges	—		4		—		4
Pension and postretirement benefits other than pensions:
Amortization of loss and prior service cost – net	—		—		1		—
Comprehensive income	$ 157		$ 251		$ 352		$ 384

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

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS


In millions	June 30, 2007			December 31, 2006
	(Unaudited)
ASSETS
Cash and equivalents	$	91		$	83
Restricted cash		49			56
Margin and collateral deposits		54			55
Receivables, less allowances of $26 and $29 for uncollectible accounts at respective dates		943			939
Accrued unbilled revenue		480			303
Inventory		249			232
Accumulated deferred income taxes – net		300			250
Derivative assets		131			56
Regulatory assets		385			554
Other current assets		113			54
Total current assets		2,795			2,582
Nonutility property – less accumulated provision for depreciation of $669 and $633 at respective dates		1,016			1,046
Nuclear decommissioning trusts		3,304			3,184
Other investments		82			62
Total investments and other assets		4,402			4,292
Utility plant, at original cost:
Transmission and distribution		18,138			17,606
Generation		1,481			1,465
Accumulated provision for depreciation		(4,927	)		(4,821	)
Construction work in progress		1,684			1,486
Nuclear fuel, at amortized cost		168			177
Total utility plant		16,544			15,913
Regulatory assets		2,821			2,818
Derivative assets		12			17
Other long-term assets		488			488
Total long-term assets		3,321			3,323

Total assets	$	27,062		$	26,110

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

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS


In millions, except share amounts	June 30, 2007			December 31, 2006
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Short-term debt	$	175		$	—
Long-term debt due within one year		312			396
Accounts payable		849			856
Accrued taxes		248			193
Accrued interest		142			114
Counterparty collateral		40			36
Customer deposits		212			198
Book overdrafts		201			140
Derivative liabilities		60			99
Regulatory liabilities		1,120			1,000
Other current liabilities		507			624
Total current liabilities		3,866			3,656
Long-term debt		5,117			5,171
Accumulated deferred income taxes – net		2,605			2,675
Accumulated deferred investment tax credits		109			112
Customer advances		161			160
Derivative liabilities		12			77
Power-purchase contracts		27			32
Accumulated provision for pensions and benefits		843			809
Asset retirement obligations		2,802			2,749
Regulatory liabilities		3,234			3,140
Other deferred credits and other long-term liabilities		1,044			802
Total deferred credits and other liabilities		10,837			10,556
Total liabilities		19,820			19,383
Commitments and contingencies (Note 6)
Minority interest		417			351
Common stock, no par value (434,888,104 shares outstanding at each date)		2,168			2,168
Additional paid-in capital		399			383
Accumulated other comprehensive loss		(13	)		(14	)
Retained earnings		3,342			2,910
Total common shareholder’s equity		5,896			5,447
Preferred and preference stock not subject to mandatory redemption		929			929
Total shareholders’ equity		6,825			6,376

Total liabilities and shareholders’ equity	$	27,062		$	26,110

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

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
In millions	2007		2006
	(Unaudited)
Cash flows from operating activities:
Net income	$ 351		$ 380
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	546		552
Realized loss on nuclear decommissioning trusts	23		—
Other amortization	50		35
Minority interest	129		117
Deferred income taxes and investment tax credits	(242	)	5
Regulatory assets – long-term	76		112
Regulatory liabilities – long-term	(1	)	(174	)
Derivative assets – long-term	5		29
Derivative liabilities – long-term	(65	)	(7	)
Other assets	(23	)	10
Other liabilities	224		(17	)
Margin and collateral deposits – net of collateral received	5		(100	)
Receivables and accrued unbilled revenue	(181	)	(224	)
Derivative assets – short-term	(75	)	196
Derivative liabilities – short-term	(39	)	84
Inventory and other current assets	(71	)	12
Regulatory assets – short-term	169		(204	)
Regulatory liabilities – short-term	121		29
Accrued interest and taxes	296		203
Accounts payable and other current liabilities	(15	)	(271	)
Net cash provided by operating activities	1,283		767
Cash flows from financing activities:
Long-term debt issued	—		500
Long-term debt issuance costs	(1	)	(9	)
Long-term debt repaid	(23	)	(350	)
Issuance of preference stock	—		196
Rate reduction notes repaid	(116	)	(116	)
Short-term debt financing – net	175		517
Change in book overdrafts	62		(86	)
Shares purchased for stock-based compensation	(112	)	(60	)
Proceeds from stock option exercises	47		23
Excess tax benefits related to stock option exercises	22		9
Minority interest	(63	)	(125	)
Dividends paid	(111	)	(154	)
Net cash provided (used) by financing activities	(120	)	345
Cash flows from investing activities:
Capital expenditures	(1,091	)	(1,089	)
Proceeds from nuclear decommissioning trust sales	2,017		1,461
Purchases of nuclear decommissioning trust investments	(2,084	)	(1,544	)
Customer advances for construction and other investments	3		7
Net cash used by investing activities	(1,155	)	(1,165	)
Net increase (decrease) in cash and equivalents	8		(53	)
Cash and equivalents, beginning of period	83		143
Cash and equivalents, end of period	$ 91		$ 90

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

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 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 three- and six-month periods ended June 30, 2007 are not necessarily indicative of the operating results for the full year.

The 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, 2006 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 2006 Annual Report on Form 10-K. SCE follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for uncertain tax positions (discussed below in “New Accounting Pronouncements”).

Certain prior-period amounts were reclassified to conform to the June 30, 2007 financial statement presentation.

Income Taxes

SCE and its eligible subsidiaries are included in Edison International’s consolidated federal income tax and combined state tax returns. Under an income tax-allocation agreement approved by the CPUC, SCE’s tax liability is computed as if it filed a separate return.

As part of the process of preparing its consolidated financial statements, SCE is required to estimate its income taxes in each jurisdiction in which it operates. This process involves estimating actual current tax expense together with assessing temporary differences resulting from differing treatment of items for tax and accounting purposes, such as depreciable property. These differences result in deferred tax assets and liabilities, which are included within SCE’s consolidated balance sheets.

Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Investment tax credits are deferred and amortized over the lives of the related properties. Interest expense and penalties associated with income taxes are reflected in the caption “Income tax expense” on the consolidated statements of income.

For a further discussion of income taxes, see Note 4.

New Accounting Pronouncements

Accounting Pronouncement Adopted

Implementation of FIN 48 resulted in a cumulative-effect adjustment that increased retained earnings by $213 million upon adoption. SCE will continue to monitor and assess new income tax developments.

Accounting Pronouncements Not Yet Adopted

In April 2007, the FASB issued FIN 39-1. FIN 39-1 amends paragraph 3 of FIN No. 39 to replace the terms conditional contracts and exchange contracts with the term derivative instruments as defined in SFAS No. 133. FIN 39-1 also states that under master netting arrangements if collateral is based on fair value, then it must be netted with the fair value of derivative assets/liabilities if an entity qualified and elected the option to net those amounts. SCE will adopt FIN 39-1 on January 1, 2008. Adoption of this position may result in netting a portion of margin and cash collateral deposits with derivative liabilities on SCE’s consolidated balance sheets, but will have no impact on SCE’s consolidated statements of income.

In February 2007, the FASB issued SFAS No. 159, which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings. Upon adoption, the first remeasurement to fair value would be reported as a cumulative-effect adjustment to the opening balance of retained earnings. SCE will adopt SFAS No. 159 on January 1, 2008. SCE is currently evaluating whether it will opt to report any financial assets and liabilities at fair value and the impact, if adopted, on its consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. SCE will adopt SFAS No. 157 on January 1, 2008. SCE is currently evaluating the impact of adopting SFAS No. 157 on its financial statements.

Sales and Use Taxes

SCE bills certain sales and use taxes levied by state or local governments to its customers. Included in these sales and use taxes are franchise fees, which SCE pays to various municipalities (based on contracts with these municipalities) in order to operate within the limits of the municipality. SCE bills these franchise fees to its customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SCE’s ability to collect from the customer, are accounted for on a gross basis and reflected in electric utility revenue and other operation and maintenance expense. SCE’s franchise fees billed to customers and recorded as operating revenue were $24 million and $27 million for the three-month periods ended June 30, 2007 and 2006, respectively, and $47 million for both six-month periods ended June 30, 2007 and 2006. When SCE acts as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. Amounts billed to and collected from customers for these taxes are being remitted to the taxing authorities and are not recognized as revenue.

Stock-Based Compensation

Stock options, performance shares, deferred stock units and, beginning in 2007, restricted stock units have been granted under Edison International’s long-term incentive compensation programs. Edison International usually does not issue new common stock for equity awards settled. Rather, a third party is used to facilitate the exercise of stock options and the purchase and delivery of outstanding common stock for settlement of option exercises, performance shares and restricted stock units. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in EIX’s common stock. Deferred stock units granted to management are settled in cash, not stock and represent a liability.

On April 26, 2007, Edison International’s shareholders approved a new incentive plan (the 2007 Performance Incentive Plan) that includes stock-based compensation. No additional awards will be granted under Edison International’s prior stock-based compensation plans on or after April 26, 2007, and all future issuances will be

made under the new plan. The maximum number of shares of Edison International’s common stock that may be issued or transferred pursuant to awards under the new incentive plan is 8.5 million shares, plus the number of any shares subject to awards issued under Edison International’s prior plans and outstanding as of April 26, 2007, which expire, cancel or terminate without being exercised or shares being issued. As of June 30, 2007, Edison International has approximately 8.4 million shares remaining for future issuance under its stock-based compensation plans. For further discussion see “Stock-Based Compensation” in Note 5.

Note 2. Derivative Instruments and Hedging Activities

SCE is exposed to commodity price risk associated with its purchases for additional capacity and ancillary services to meet its peak energy requirements as well as exposure to natural gas prices associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including the Mountainview plant. SCE’s realized and unrealized gains and losses arising from derivative instruments are reflected in purchased-power expense and offset through the provision for regulatory adjustment clauses – net on the consolidated statements of income and thus do not affect earnings, but may temporarily affect cash flows.

The following is a summary of purchased-power expense:


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2007			2006			2007			2006
Purchased-power from bilateral contracts, QFs, ISO, and exchange energy	$	787		$	706		$	1,237		$	1,321
Unrealized (gains) / losses on economic hedging activities		45			9			(89	)		342
Realized (gains) / losses on economic hedging activities		23			91			52			166
Energy settlements and refunds		(26	)		(37	)		(54	)		(46	)
Total purchased-power expense	$	829		$	769		$	1,146		$	1,783

The increase for the three months ended June 30, 2007 in net unrealized losses on economic hedging activities was primarily due to lower forward natural gas prices in the second quarter of 2007, compared to the same period in 2006. The increase for the six months ended June 30, 2007 in net unrealized gains on economic hedging activities was primarily a result of changes in SCE’s gas hedge portfolio mix.

Note 3. Liabilities and Lines of Credit

Short-term Debt

Short-term debt is generally used to finance fuel inventories, balancing account undercollections and general, temporary cash requirements. At June 30, 2007, the outstanding short-term debt and weighted-average interest rate was $175 million at 5.56%. This short-term debt is supported by a $2.5 billion credit line of which $2.1 billion was available as of June 30, 2007.

Note 4. Income Taxes

SCE’s composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. SCE’s effective tax rate from operations was 28% and 25% for the three- and six-month periods ended June 30, 2007, respectively, as compared to 37% and 38% for the respective periods in 2006. The decreased effective tax rate was primarily caused by reductions made to the income tax reserves during the first quarter of 2007 to reflect progress in an administrative appeal process with the IRS related to the income tax treatment of costs associated with environmental remediation and also due to reductions made to the income tax reserves during the second quarter of 2007 to reflect settlement of a state tax issue related to the April 2007 State Notice of Proposed Adjustment discussed below. Additional decreases to the 2007 effective tax rate resulted from accruing lower tax reserves interest expense in 2007 as compared to 2006 as

a result of implementing FIN 48 and from year over year changes in property related flow-through items. In addition, the decreased effective tax rate in the second quarter of 2007 resulted from a reduction in pre-tax income.

The net liability recorded for uncertain tax positions was $105 million and $98 million as of June 30, 2007 and the date of adoption (January 1, 2007) of FIN 48, respectively. The net liability as of June 30, 2007 and the date of adoption consists of $309 million and $335 million, respectively, of unrecognized tax benefits, partially offset by $204 million and $237 million, respectively, of recognized tax benefits representing the expected settlement outcome of affirmative claims made or expected to be made that meet the recognition requirement pursuant to FIN 48. The change in the unrecognized tax benefits from the date of adoption reflects decreases of $12 million from positions taken in prior periods and $14 million from positions taken in 2007. The total amount of unrecognized tax benefits as of June 30, 2007 and the date of adoption that, if recognized, would affect the effective tax rate was $53 million and $35 million, respectively.

The unrecognized tax benefits, as of June 30, 2007 and the date of adoption, do not reflect affirmative claims of $1.6 billion and $1.7 billion respectively. These claims consist of $64 million and $71 million representing the difference between the amount filed on amended tax returns and the amount recognized pursuant to FIN 48 and $1.5 billion and $1.6 billion of claims which have been filed on amended tax returns but have not met the recognition requirement pursuant to FIN 48, the majority of which have been denied as part of an IRS examination. These affirmative claims remain unpaid by the IRS and no receivable has been accrued. Edison International is vigorously defending these affirmative positions in IRS administrative appeals.

The total amount of accrued interest and penalties was $85 million and $65 million as of June 30, 2007 and the date of adoption, respectively. The total amount of interest expense and penalties recognized in income tax expense for the three months ended June 30, 2007 was $4 million. The total benefit recognized in income tax expense for the six months ended June 30, 2007 was $35 million.

Edison International and its subsidiaries remain subject to examination and administrative appeals by the IRS from 1994 – present. In addition, the statute of limitations remains open from 1986 – 1993 for certain affirmative claims. In July 2007, Edison International and its subsidiaries received a Notice of Proposed Adjustment from the IRS accepting an affirmative claim position involving the taxability of balancing account over-collections. This issue was addressed as part of the ongoing IRS examinations and administrative appeals process. The tax years affected by this Notice of Proposed Adjustment remain subject to examination and administrative appeals. The cash and earnings impacts of this position are dependent on the ultimate settlement of all issues in these tax years. SCE expects earnings and cash flows to increase within the range of $65 million to $75 million and $275 million to $300 million, respectively.

In April 2007, Edison International and its subsidiaries received a Notice of Proposed Adjustment from the California Franchise Tax Board for tax years 2001 and 2002. In June 2007, Edison International and its subsidiaries filed their protest to deficiencies asserted in the April 2007 Notice of Proposed Adjustment. Edison International and its subsidiaries remain subject to examination by the California Franchise Tax Board for tax years from 2003 – present. Edison International and its subsidiaries are also subject to examination by select state tax authorities, with varying statute of limitations. Some state jurisdictions follow the federal statute for comparable issues.

Edison International and SCE continue their efforts to resolve open tax issues with the IRS and State authorities. The timing for resolving these open tax positions is subject to uncertainty, but it is reasonably possible that some portion of these open tax positions could be resolved in the next 12 months.

As a matter of course, SCE is regularly audited by federal and state taxing authorities. For further discussion of this matter, see “Federal and State Income Taxes” in Note 6.

Note 5. Compensation and Benefits Plans

Pension Plans

SCE previously disclosed in Note 5 of “Notes to Consolidated Financial Statements” included in its 2006 Annual Report on Form 10-K that it expects to contribute approximately $50 million to its pension plan in 2007. As of June 30, 2007, SCE has made $45 million in contributions related to 2006 and $13 million related to 2007 and estimates to make $24 million of additional contributions in the last six months of 2007. Expected contribution funding could vary from anticipated amounts depending on the funded status at year-end and tax-deductible funding limitations.

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.

Expense components are:


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2007		2006		2007		2006
	(Unaudited)
Service cost	$ 26		$ 26		$ 52		$ 51
Interest cost	44		43		88		85
Expected return on plan assets	(61	)	(57	)	(122	)	(113	)
Special termination benefits	—		4		—		4
Amortization of prior service cost	4		4		9		8
Amortization of net loss	1		—		1		1
Subtotal	14		20		28		36
Regulatory adjustment – deferred	1		(1	)	2		(3	)
Total expense recognized	$ 15		$ 19		$ 30		$ 33

Postretirement Benefits Other Than Pensions

SCE previously disclosed in Note 6 of “Notes to Consolidated Financial Statements” included in its 2006 Annual Report on Form 10-K that it expects to contribute approximately $41 million to its postretirement benefits other than pension plans in 2007. As of June 30, 2007, SCE has made no contributions related to 2006 and $10 million related to 2007 and estimates to make $31 million of additional contributions in the last six months of 2007. Expected contribution funding could vary from anticipated amounts depending on the funded status at year-end and tax-deductible funding limitations.

Expense components are:


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2007		2006		2007		2006
	(Unaudited)
Service cost	$ 10		$ 12		$ 20		$ 24
Interest cost	31		30		62		61
Expected return on plan assets	(30	)	(27	)	(60	)	(54	)
Special termination benefits	—		3		—		3
Amortization of prior service credit	(7	)	(8	)	(14	)	(15	)
Amortization of net loss	6		12		12		23
Total expense recognized	$ 10		$ 22		$ 20		$ 42

Stock-Based Compensation

Total stock-based compensation expense (reflected in the caption “Other operation and maintenance” on the consolidated statements of income) was $11 million and $6 million for the three-month periods ended June 30, 2007 and 2006, respectively and was $14 million and $12 million for the six-month periods ended June 30, 2007 and 2006, respectively. The income tax benefit recognized in the consolidated statements of income was $4 million and $2 million for the three-month periods ended June 30, 2007 and 2006, respectively and was $6 million and $5 million for the six-month periods ended June 30, 2007 and 2006, respectively. Total stock-based compensation cost capitalized was $2 million and $1 million for the three-month periods ended June 30, 2007 and 2006 and was $3 million and $2 million for the six-month periods ended June 30, 2007 and 2006, respectively.

Stock Options

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


	Weighted - Average
	Stock Options		Exercise Price		Remaining Contractual Term (Years)	Aggregate Intrinsic Value
Outstanding at December 31, 2006	7,761,336		$	26.78
Granted	907,429		$	47.56
Forfeited	(31,399	)	$	38.61
Exercised	(2,034,693	)	$	22.93
Outstanding at June 30, 2007	6,602,673		$	30.79	6.84
Vested and expected to vest at June 30, 2007	6,313,607		$	30.42	6.78	$	148,669,661
Exercisable at June 30, 2007	3,339,179		$	23.78	5.54	$	100,801,466

Stock options granted in 2007 do not accrue dividend equivalents.

The amount of cash used to settle stock options exercised was $54 million and $16 million for the three-month periods ended June 30, 2007 and 2006, respectively, and $104 million and $45 million for the six-month periods ended June 30, 2007 and 2006, respectively. Cash received from options exercised was $23 million and $9 million for the three-month periods ended June 30, 2007 and 2006, respectively, and $47 million and $23 million for the six-month periods ended June 30, 2007 and 2006, respectively. The estimated tax benefit from options exercised was $13 million and $3 million for the three-month periods ended June 30, 2007 and 2006, respectively, and $23 million and $9 million for the six-month periods ended June 30, 2007 and 2006, respectively.

Note 6. Commitments and Contingencies

Lease Commitments

SCE entered into a new operating lease for a power contract during the first six months of 2007. SCE’s additional operating lease commitments for this new power contract are currently estimated to be $68 million for 2008 and $114 million for each of the years 2009, 2010 and 2011.

SCE executed a power purchase contract in June 2007 which met the requirements for capital leases. As of June 30, 2007, the capital lease requires future minimum lease payments of $28 million (approximately $1 million per year) through May 2027. As of June 30, 2007, the executory costs and imputed interest for this capital lease were $11 million and $7 million, respectively.

Other Commitments

SCE entered into service contracts associated with uranium enrichment and fuel fabrication during the first three months of 2007. As a result, SCE’s fuel supply commitments for the remainder of 2007 are estimated to be $143 million.

Indemnities

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.

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.

SCE believes that it is in substantial compliance with environmental regulatory requirements; however, 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.

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 $127 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 32 immaterial sites whose total liability ranges from $2 million (the recorded minimum liability) to $8 million.

The CPUC allows SCE to recover 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 $72 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 $31 million. Recorded costs for the 12 months ended June 30, 2007 were $18 million.

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 received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994 – 1996 and 1997 – 1999 tax years, respectively. Edison International expects to conclude the administrative phase of the audit of the 1994 – 1996 tax years by the end of 2007. Many of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of penalties), if any, would be deductible on future tax returns of Edison International. Edison International has also submitted affirmative claims to the IRS and state tax agencies which are being addressed in administrative proceedings. Any benefits would be recorded at the earlier of when Edison International believes that the affirmative claim position has a more likely than not probability of being sustained or when a settlement is consummated. Certain affirmative claims have been recorded as part of the implementation of FIN 48.

The IRS Revenue Agent Report for the 1997 – 1999 audit also asserted deficiencies with respect to a transaction entered into by an SCE subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability company. This matter is currently being considered by the Administrative Appeals branch of the IRS where Edison International is defending its tax return position with respect to this transaction.

In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 – 2002 to mitigate the possible imposition of new California penalty provisions on transactions that may be considered as listed or substantially similar to listed transactions described in an IRS notice that was published in 2001. These transactions include the SCE subsidiary contingent liability company transaction described above. Edison International filed these amended returns under protest retaining its appeal rights.

In December 2006, Edison International reached a settlement with the California Franchise Tax Board regarding the sourcing of gross receipts from the sale of electric services for California state tax apportionment purposes for tax years 1981 to 2004. In the fourth quarter of 2006, SCE recorded a $49 million benefit related to a tax reserve adjustment as a result of this settlement. In addition to this tax reserve adjustment, SCE received a net cash refund of $52 million in April 2007 as a result of this same settlement.

FERC Refund Proceedings

SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets during the energy crisis in California in 2000 – 2001 or who benefited from the manipulation by receiving inflated market prices. SCE is required to refund to customers 90% of any refunds actually realized by SCE, net of litigation costs, and 10% will be retained by SCE as a shareholder incentive.

During the course of the refund proceedings, the FERC ruled that governmental power sellers, like private generators and marketers that sold into the California market, should refund the excessive prices they received during the crisis period. However, on September 21, 2005, the Ninth Circuit ruled in Bonneville v. FERC that the FERC does not have authority directly to enforce its refund orders against governmental power sellers. The Court, however, clarified that its decision does not preclude SCE or other parties from pursuing civil claims against the governmental power sellers. On March 16, 2006, SCE, PG&E and the California Electricity Oversight Board jointly filed suit in federal court against several governmental power sellers, seeking damages based on the reduced prices set by the FERC for transactions during the crisis period. In March 2007, the federal court dismissed this suit concluding that the claims should have been filed in state court. SCE, along with PG&E, the Oversight Board and SDG&E, refiled on April 29, 2007 in the Los Angeles Superior Court. In addition, on March 12, 2007, SCE, PG&E and the Oversight Board filed a similar group of claims in the U.S. Court of Federal Claims against two federal agencies that sold power into California during the energy crisis. SCE cannot predict whether it may be able to recover any additional refunds from governmental power sellers as a result of these suits.

On April 2, 2007, SCE, PG&E, SDG&E, the Oversight Board, the CPUC, and the California Attorney General (the California Parties), in anticipation of the Ninth Circuit remand of its rulings in Bonneville to the FERC for further action, filed pleadings at the FERC requesting that it order the California ISO and the PX to complete their calculations of refunds owed to purchasers by all sellers, including governmental sellers. On April 5, 2007, the Ninth Circuit issued the remand of Bonneville to the FERC. On April 17 and 18, 2007, several governmental power sellers filed pleadings at the FERC opposing the California Parties’ request and contending that Bonneville required FERC to order the California ISO and PX to immediately return collateral previously deposited by governmental sellers and pay receivables that governmental sellers claim are owed to them. This matter remains pending at the FERC.

In November 2005, SCE and other parties entered into a settlement agreement with Enron Corporation and a number of its affiliates, most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In 2006, SCE received distributions of approximately $55 million on its allowed bankruptcy claim. In April 2007, SCE received and recorded an additional distribution on its allowed bankruptcy claim of approximately $12 million and 55,465 shares of Portland General Electric Company stock, with an aggregate value of less than $2 million. Additional distributions are expected but SCE cannot currently predict the amount or timing of such distributions.

On August 2, 2006, the Ninth Circuit issued an opinion regarding the scope of refunds issued by the FERC. The Ninth Circuit broadened the time period during which refunds could be ordered to include the summer of 2000 based on evidence of pervasive tariff violations and broadened the categories of transactions that could be subject to refund. As a result of this decision, SCE may be able to recover additional refunds from sellers of electricity during the crisis with whom settlements have not been reached.

Investigations Regarding Performance Incentives Rewards

SCE was eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability.

SCE conducted investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings of misconduct and misreporting as further discussed below.

Customer Satisfaction

SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service planning group of SCE’s transmission and distribution business unit altered or omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The results of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or penalties for customer satisfaction. SCE recorded aggregate customer satisfaction rewards of $28 million over the period 1997 – 2000. Potential customer satisfaction rewards aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of approximately $10 million for 2003.

Following its internal investigation, SCE proposed to refund to ratepayers $7 million of the PBR rewards previously received and forgo an additional $5 million of the PBR rewards pending that are both attributable to the design organization’s portion of the customer satisfaction rewards for the entire PBR period (1997 – 2003). In addition, SCE also proposed to refund all of the approximately $2 million of customer satisfaction rewards associated with meter reading.

SCE has taken remedial action as to the customer satisfaction survey misconduct by disciplining and/or terminating certain employees, including several supervisory personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls over data collection and processing. Performance incentive rewards for customer satisfaction expired in 2003 pursuant to the 2003 GRC.

Employee Injury and Illness Reporting

In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE’s employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has recognized $20 million in employee safety incentives for 1997 through 2000 and, based on SCE’s records, may be entitled to an additional $15 million for 2001 through 2003.

On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings concerning SCE’s performance under the PBR incentive mechanism for injury and illness reporting. SCE disclosed in the investigative findings to the CPUC that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid incidents.

As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the mechanism and return to ratepayers the $20 million it had already received. SCE has also proposed to withdraw the pending rewards for the 2001 – 2003 time frames.

SCE has taken remedial action to address the issues identified, including revising its organizational structure and overall program for environmental, health and safety compliance, disciplining employees who committed wrongdoing and terminating one employee. SCE submitted a report on the results of its investigation to the CPUC on December 3, 2004.

System Reliability

In light of the problems uncovered with the PBR mechanisms discussed above, SCE conducted an investigation into the third PBR metric, system reliability. On February 28, 2005, SCE provided its final investigatory report to the CPUC concluding that the reliability reporting system is working as intended.

CPUC Investigation

On June 15, 2006, the CPUC instituted a formal investigation to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer satisfaction, employee safety and system reliability portions of PBR. The CPUC also may consider whether to impose additional penalties on SCE.

In June 2006, the CPSD of the CPUC issued its report regarding SCE’s PBR program, recommending that the CPUC impose various refunds and penalties on SCE. Subsequently, in September 2006, the CPSD and other intervenors, such as the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network, filed testimony on these matters recommending various refunds and penalties to be imposed upon SCE. On October 16, 2006, SCE filed testimony opposing the various refund and penalty recommendations of the CPSD and other intervenors. Based on SCE’s proposal for refunds and the combined recommendations of the CPSD and other intervenors, the potential refunds and penalties could range from $52 million up to $388 million. SCE has recorded an accrual at the lower end of this range of potential loss and is accruing interest on collected amounts that SCE has proposed to refund to customers. Evidentiary hearings which addressed the planning and meter reading components of customer satisfaction, safety, issues related to SCE’s administration of the survey, and statutory fines associated with those matters took place in the fourth quarter of 2006. System reliability issues and the remaining customer satisfaction components of the investigation will be addressed in a second phase of the proceeding, which will commence with the filing of SCE’s opening testimony in September 2007. A Presiding Officer’s Decision has not yet been received on the issues addressed during phase one and SCE cannot predict when such decision will be issued. At this time, SCE cannot predict the outcome of these matters or reasonably estimate the potential amount of any additional refunds, disallowances, or penalties that may be required above the lower end of the range.

ISO Disputed Charges

On April 20, 2004, the FERC issued an order 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 March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. On May 25, 2007, the FERC issued a procedural order granting the rehearing application for the purpose of allowing the FERC to give it further consideration. In a future order, FERC may deny the rehearing request or grant the requested relief in whole or in part. SCE believes that the most substantive FERC order correctly allocates responsibility for these ISO charges. However, SCE cannot provide assurance as to the final outcome of the rehearing. 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, SCE may seek

recovery in its reliability service rates. SCE cannot provide any assurance that recovery of these charges in its reliability service rates would be permitted.

Midway-Sunset Cogeneration Company

San Joaquin Energy Company, a wholly owned subsidiary of EME, owns a 50% general partnership interest in Midway-Sunset, which owns a 225-MW cogeneration facility near Fellows, California. Midway-Sunset is a party to several proceedings pending at the FERC because Midway-Sunset was a seller in the PX and ISO markets during 2000 and 2001, both for its own account and on behalf of SCE and PG&E, the utilities to which the majority of Midway-Sunset’s power was contracted for sale. As a seller into the PX and ISO markets, Midway- Sunset is potentially liable for refunds to purchasers in these markets. See discussion above in “FERC Refund Proceedings.”

The claims asserted against Midway-Sunset for refunds related to power sold into the PX and ISO markets, including power sold on behalf of SCE and PG&E, are estimated to be less than $70 million for all periods under consideration. Midway-Sunset did not retain any proceeds from power sold into the PX and ISO markets on behalf of SCE and PG&E in excess of the amounts to which it was entitled under the pre-existing power sales contracts, but instead passed through those proceeds to the utilities. Since the proceeds were passed through to the utilities, EME believes that PG&E and SCE are obligated to reimburse Midway-Sunset for any refund liability that it incurs as a result of sales made into the PX and ISO markets on their behalves. During this period, amounts SCE received from Midway-Sunset were credited to SCE’s customers against power purchase expenses through the ratemaking mechanism in place at that time. SCE believes that any net amounts reimbursed to Midway-Sunset would be substantially recoverable from its customers through current regulatory mechanisms. SCE does not expect any reimbursement to Midway-Sunset to have a material impact on earnings.

Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 in the District Court 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 April 2004, the District Court dismissed SCE’s motion for summary judgment and concluded that a 2003 U.S. Supreme Court decision in an on-going related lawsuit by the Navajo Nation against the U.S. Government did not preclude the Navajo Nation from pursuing its RICO and intentional tort claims.

Pursuant to a joint request of the parties, the District Court granted a stay of the action on October 5, 2004 to allow the parties to attempt to negotiate a resolution of the issues associated with Mohave with the assistance of a facilitator. An initial organizational session was held with the facilitator on October 14, 2004 and negotiations are on-going. On July 28, 2005, the District Court issued an order removing the case from its active calendar, subject to reinstatement at the request of any party. On April 30, 2007, the District Court, in light of the duration of the stay, issued a minute order directing that the parties file a joint status report and recommendation for future proceedings no later than June 1, 2007. In their June 1, 2007 joint status report, the parties advised the District Court of the history and status of their settlement efforts, including the potential for further discussions. Following its receipt of the status report, the District Court continued the stay and directed the parties to file a further joint status report by October 5, 2007.

SCE cannot predict the outcome of the 1999 Navajo Nation’s complaint against SCE, the ultimate impact on the complaint of the Supreme Court’s 2003 decision and the on-going litigation by the Navajo Nation against the

Government in the related case, or the impact on the facilitated negotiations of the Mohave co-owners’ announced decisions to discontinue efforts to return Mohave to service.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $10.8 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. The current maximum deferred premium for each nuclear incident is $101 million per reactor, but not more than $15 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 will be adjusted for inflation on a 5-year schedule. The next inflation adjustment will occur no later than August 20, 2008. Based on its ownership interests, SCE could be required to pay a maximum of $201 million per nuclear incident. However, it would have to pay no more than $30 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 regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators.

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 $44 million per year. Insurance premiums are charged to operating expense.

Palo Verde Nuclear Generating Station Outage and Inspection

Between December 2005 when Palo Verde Unit 1 returned to service from its refueling and steam generator replacement outage and March 2006, Palo Verde Unit 1 operated at between 25% and 32% power level. The need to operate at a reduced power level was due to the vibration level in one of the unit’s shutdown cooling lines. On March 18, 2006, Arizona Public Service, the operating agent for Palo Verde Unit 1, removed the unit from service in order to resolve the problem. The vibration problem was resolved and Palo Verde Unit 1 was returned to service on July 7, 2006. Incremental replacement power costs incurred during the outage and periods of reduced power operation of approximately $32 million are expected to be recovered through the ERRA rate-making mechanism.

The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. A follow-up to the first inspection resulted in a finding that Palo Verde had not established adequate measures to ensure that certain corrective actions were effective to address the root cause of the event. The second recent inspection identified five violations, but none of those resulted in increased NRC scrutiny. The most recent inspection, concerning the failure of an emergency backup generator at Palo Verde Unit 3 identified a violation that, combined with the first inspection finding, will cause the NRC to undertake additional oversight inspections of Palo Verde. In addition, Palo Verde will be required to take additional corrective actions, including surveys of its plant personnel and self-assessments of its programs and procedures, which will increase costs to both Palo Verde and its co-owners, including SCE. Because the surveys and self-assessments have not yet occurred and are critical to determining what other actions Palo Verde will need to take to address the NRC’s concerns, SCE cannot calculate the total increase in costs, but presently estimates that operation and maintenance costs at Palo

Verde will increase by a minimum of $22 million per year through 2009. SCE also is unable to estimate how long SCE will continue to incur these costs.

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.

On October 19, 2006, the CPUC issued a decision that, among other things, implemented a “cumulative deficit banking” feature which would carry forward and accumulate annual deficits until the deficit has been satisfied at a later time through actual deliveries of eligible renewable energy and made an accounting determination that defines the annual targets for each year of the renewable portfolio standards program. Based on terms of the controlling California statute, in March 2007, SCE successfully challenged the CPUC’s accounting determination of SCE’s annual targets. This change is expected to enable SCE to meet its target for 2007.

On April 3, 2007, SCE filed its renewable portfolio standard compliance report for 2004 through 2006. The compliance report confirms that SCE met its renewable goals for each of these years. In light of the annual target revisions that resulted from the March 2007 successful challenge to the CPUC’s accounting determination, the report also projects that SCE will meet its renewable goals for 2007 and 2008 but could have a potential deficit in 2009. The potential deficit in 2009, however, does not take into account future procurement opportunities or the full utilization by SCE of the CPUC’s rules for flexible compliance with annual targets. SCE continues to engage in several initiatives to procure additional renewable resources, including formal solicitations approved by the CPUC, bilateral negotiations with individual projects and other initiatives.

Under current CPUC decisions, potential penalties for SCE’s failure to achieve its renewable procurement objectives for any year would be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance filing. Under the CPUC’s current rules, the maximum penalty for failing to achieve renewable procurement targets is $25 million per year.

Scheduling Coordinator Tariff Dispute

Pursuant to the Amended and Restated Exchange Agreement, SCE serves as a scheduling coordinator for the DWP over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund for FERC-authorized scheduling coordinator charges incurred by SCE on the DWP’s behalf. The scheduling coordinator charges are billed to the DWP under a FERC tariff that remains subject to dispute. The DWP has paid the amounts billed under protest but requested that the FERC declare that SCE was obligated to serve as the DWP’s scheduling coordinator without charge. The FERC accepted SCE’s tariff for filing, but held that the rates charged to the DWP have not been shown to be just and reasonable and thus made them subject to refund and further review by the FERC. In September 2006, SCE and DWP agreed to a term sheet that would settle this dispute, among others surrounding the Exchange Agreement. The settlement was approved by the FERC on July 27, 2007 and is expected to be approved by the City of Los Angeles in the second half of 2007. As of June 30, 2007, SCE has an accrued liability of $47 million (including $6 million of interest) for the potential refunds representing charges collected. Under the settlement terms, SCE would refund to the DWP the scheduling coordinator charges collected, with an offset for contract losses, and will be able to recover the scheduling coordinator charges from all transmission grid customers.

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 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 through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the 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 case was stayed through April 7, 2006. On June 5, 2006, the Court of Federal Claims lifted the stay on SCE’s case and established a discovery schedule. A Joint Status Report is due on February 22, 2008, regarding further proceedings in this case, presumably including the setting of a trial date.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel storage installation where all of Unit 1’s spent fuel located at San Onofre is stored. There are now sufficient dry casks and modules available at the independent spent fuel storage installation to meet plant requirements through 2008. SCE, as operating agent, plans to continually load casks on a schedule to maintain full core off-load capability for both units in order to meet the plant requirements until 2022 (the end of the current NRC operating license).

In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed an independent spent fuel storage facility. Arizona Public Service, as operating agent, plans to continually load dry casks on a schedule to maintain full core off-load capability for all three units.

Note 7. Supplemental Cash Flows Information


	Six Months Ended June 30,
In millions	2007			2006
	(Unaudited)
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	141		$	146
Tax payments (receipts)		(18	)		29
Noncash investing and financing activities:
Details of debt exchange:
Pollution-control bonds redeemed	$	—		$	(331	)
Pollution-control bonds issued		—			331
Details of obligation under capital lease:
Capital lease asset purchased	$	(10	)	$	—
Capital lease obligation issued		10			—
Dividends declared but not paid:
Common Stock	$	25		$	60
Preferred and Preference stock not subject to mandatory redemption		13			13

Note 8. Regulatory Assets and Liabilities

Regulatory assets included in the consolidated balance sheets are:


In millions	June 30, 2007		December 31, 2006
	(Unaudited)
Current:
Regulatory balancing accounts	$	104	$	128
Rate reduction notes – transition cost deferral		111		219
Direct access procurement charges		20		63
Energy derivatives		58		88
Purchased-power settlements		18		31
Deferred FTR proceeds		47		14
Other		27		11
		385		554
Long-term:
Flow-through taxes – net		1,140		1,023
Unamortized nuclear investment – net		421		435
Nuclear-related asset retirement obligation investment – net		307		317
Unamortized coal plant investment – net		98		102
Unamortized loss on reacquired debt		308		318
SFAS No. 158 pensions and postretirement benefits		305		303
Energy derivatives		72		145
Environmental remediation		72		77
Other		98		98
		2,821		2,818
Total Regulatory Assets	$	3,206	$	3,372

Deferred FTR proceeds represent the deferral of congestion revenue SCE received as a transmission owner from the annual ISO FTR auction. The deferred FTR proceeds will be recognized over the period April 2007 through January 2008.

Regulatory liabilities included in the consolidated balance sheets are:


In millions	June 30, 2007		December 31, 2006
	(Unaudited)
Current:
Regulatory balancing accounts	$	1,000	$	912
Direct access procurement charges		20		63
Energy derivatives		12		7
Deferred FTR costs		84		11
Other		4		7
		1,120		1,000
Long-term:
Asset retirement obligations		799		732
Costs of removal		2,190		2,158
SFAS No. 158 pensions and other postretirement benefits		153		145
Energy derivatives		14		27
Employee benefit plans		78		78
		3,234		3,140
Total Regulatory Liabilities	$	4,354	$	4,140

Deferred FTR costs represent the deferral of the costs associated with FTRs that SCE purchased during the annual ISO auction process. The FTRs provide SCE with scheduling priority in certain transmission grid congestion areas in the day-ahead market. The FTRs meet the definition of a derivative instrument and are recorded at fair value and marked to market each reporting period. Any fair value change for FTRs is reflected in the deferred FTR costs regulatory liability. The deferred FTR costs are recognized as FTRs are used or expire during the period April 2007 through March 2008.

Note 9. Business Segments

SCE’s reportable business segments include the rate-regulated electric utility segment and the VIEs segment. The VIEs were consolidated as of March 31, 2004. Additional details on the VIE segment are in Note 14 of “Notes to Consolidated Financial Statements” included in SCE’s 2006 Annual Report on Form 10-K. 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 business segment information including all line items with VIE activities, is:


In millions	Electric Utility		VIEs		Eliminations			SCE
	(Unaudited)
Balance Sheet Items as of June 30, 2007:
Cash and equivalents	$	5	$	86	$	—		$	91
Accounts receivable – net		905		129		(91	)		943
Inventory		235		14		—			249
Other current assets		104		9		—			113
Nonutility property – net of depreciation		711		305		—			1,016
Other long-term assets		484		4		—			488
Total assets		26,606		547		(91	)		27,062
Long-term debt due within one year		280		32		—			312
Accounts payable		857		83		(91	)		849
Other current liabilities		506		1		—			507
Asset retirement obligations		2,788		14		—			2,802
Minority interest		—		417		—			417
Total liabilities and shareholders’ equity	$	26,606	$	547	$	(91	)	$	27,062

Balance Sheet Items as of December 31, 2006:
Cash and equivalents	$	5	$	78	$	—		$	83
Accounts receivable – net		893		141		(95	)		939
Inventory		218		14		—			232
Other current assets		50		4		—			54
Nonutility property – net of depreciation		727		319		—			1,046
Other long-term assets		481		7		—			488
Total assets		25,642		563		(95	)		26,110
Accounts payable		809		142		(95	)		856
Other current liabilities		622		2		—			624
Long-term debt		5,117		54		—			5,171
Asset retirement obligations		2,735		14		—			2,749
Minority interest		—		351		—			351
Total liabilities and shareholders’ equity	$	25,642	$	563	$	(95	)	$	26,110


In millions	Electric Utility		VIEs		Eliminations*			SCE
	(Unaudited)
Income Statement Items for the Three Months Ended June 30, 2007:
Operating revenue	$	2,349	$	308	$	(197	)	$	2,460
Fuel		98		187		—			285
Purchased power		1,026		—		(197	)		829
Other operation and maintenance		640		21		—			661
Depreciation, decommissioning and amortization		262		9		—			271
Total operating expenses		2,048		217		(197	)		2,068
Operating income		301		91		—			392
Interest income		10		—		—			10
Interest expense – net of amounts capitalized		105		—		—			105
Income tax expense		61		—		—			61
Minority interest		—		91		—			91
Net income	$	157	$	—	$	—		$	157

Income Statement Items for the Three Months Ended June 30, 2006:
Operating revenue	$	2,435	$	263	$	(177	)	$	2,521
Fuel		76		161		—			237
Purchased power		946		—		(177	)		769
Other operation and maintenance		613		26		—			639
Depreciation, decommissioning and amortization		291		9		—			300
Total operating expenses		1,966		196		(177	)		1,985
Operating income		469		67		—			536
Interest income		15		—		—			15
Interest expense – net of amounts capitalized		102		—		—			102
Income tax expense		145		—		—			145
Minority interest		—		67		—			67
Net income	$	247	$	—	$	—		$	247

Income Statement Items for the Six Months Ended June 30, 2007:
Operating revenue	$	4,478	$	568	$	(364	)	$	4,682
Fuel		221		374		—			595
Purchased power		1,510		—		(364	)		1,146
Other operation and maintenance		1,215		47		—			1,262
Depreciation, decommissioning and amortization		528		18		—			546
Total operating expenses		3,839		439		(364	)		3,914
Operating income		639		129		—			768
Interest income		21		—		—			21
Interest expense – net of amounts capitalized		213		—		—			213
Income tax expense		114		—		—			114
Minority interest		—		129		—			129
Net income	$	351	$	—	$	—		$	351

Income Statement Items for the Six Months Ended June 30, 2006:
Operating revenue	$	4,535	$	572	$	(368	)	$	4,739
Fuel		163		385		—			548
Purchased power		2,151		—		(368	)		1,783
Other operation and maintenance		1,202		52		—			1,254
Depreciation, decommissioning and amortization		534		18		—			552
Total operating expenses		3,783		455		(368	)		3,870
Operating income		752		117		—			869
Interest income		30		—		—			30
Interest expense – net of amounts capitalized		199		—		—			199
Income tax expense		228		—		—			228
Minority interest		—		117		—			117
Net income	$	380	$	—	$	—		$	380

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

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

This Management’s Discussion and Analysis of Financial Condition and Results of Operation for the three- and six-month periods ended June 30, 2007 discusses material changes in the financial condition, results of operations and other developments of SCE since December 31, 2006, and as compared to the three-month period ended March 31, 2006. This discussion presumes that the reader has read or has access to SCE’s MD&A for the calendar year 2006 (the year-ended 2006 MD&A), which was included in SCE’s 2006 annual report to shareholders and incorporated by reference into SCE’s Annual Report on Form 10-K for the year ended December 31, 2006, 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 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;

•

access to capital markets and the cost of capital;

•

changes in interest rates and rates of inflation;

•

governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market;

•

environmental regulations 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, and availability and cost of spare parts and repairs;

•

the availability of labor, equipment and materials;

•

the ability to obtain sufficient insurance, including insurance relating to SCE’s nuclear facilities;

•

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

•

the cost and availability of coal, natural gas, fuel oil, nuclear fuel, and associated transportation;

•

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

•

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

•

general political, economic and business conditions;

•

weather conditions, natural disasters and other unforeseen events;

•

changes in the fair value of investments and other assets; 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 2006 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 includes information about SCE, an investor-owned utility company providing electricity to retail customers in central, coastal and southern California. SCE is regulated by the CPUC and FERC.

This MD&A is presented in 8 major sections: (1) current developments; (2) liquidity; (3) regulatory matters; (4) other developments; (5) market risk exposures; (6) results of operations and historical cash flow analysis; (7) new accounting pronouncements; and (8) commitments and indemnities.

CURRENT DEVELOPMENTS

This section is intended to be a summary of those current developments that management believes are of most importance since year-end December 31, 2006. This section is not intended to be an all-inclusive list of all current developments and should be read together with all sections of this MD&A.

2008 Cost of Capital Proceeding

On May 8, 2007, SCE filed its 2008 cost of capital application requesting a rate-making capital structure of 43% long-term debt, 9% preferred equity and 48% common equity. In addition, SCE is seeking a cost of long-term debt of 6.20%, cost of preferred equity of 5.98% and a return on common equity of 11.80%. SCE expects a decision on the 2008 cost of capital application by the end of 2007.

2009 General Rate Case

On July 23, 2007, SCE tendered to the CPUC’s DRA its NOI to file a 2009 GRC. The NOI indicates that SCE’s GRC application will request a 2009 base rate revenue requirement of $5.19 billion, an increase of approximately $856 million over the projected 2008 authorized base rate revenue requirement. After considering the effects of sales growth and other offsets, SCE’s request would be a $724 million increase over current authorized base rate revenue. If the CPUC approves these requested increases and allocates them to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 16.2% and 6.2%, respectively. The requested revenue requirement increase is necessary for SCE to build facilities to serve new customers, reinforce its system to accommodate customer load growth, replace aging infrastructure, meet regulatory requirements in generation and electricity procurement, fund increased operations and maintenance costs, and provide for increased costs to recruit, train, and retain employees in light of anticipated retirements. The NOI also identifies that SCE’s application will propose a post-test year ratemaking mechanism which would result in 2010 and 2011 base rate revenue requirement increases, net of sales growth, of $250.5 million and $285.3 million, respectively, for the same reasons. SCE will also be requesting in its application that Mountainview be included in utility rate base and its operating costs be recovered through the 2009 GRC rather than the current structure under which SCE recovers Mountainview generating costs through a power purchase agreement.

The NOI includes a draft of the upcoming GRC application and testimony. The CPUC’s Rate Case Plan decision initially assigns to DRA the role of ensuring that a utility’s NOI substantially complies with the documentation requirements of that decision. The DRA is required to notify SCE of any deficiencies in the NOI by August 17, 2007. SCE can file its 2009 GRC application no sooner than 60 days after curing any such deficiencies. A final decision on SCE’s 2009 GRC is expected by December 2008.

SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted.

EdisonSmartConnect^tm

SCE’s EdisonSmartConnecttm project involves installing state-of-the-art “smart” meters in approximately 5.3 million households and small businesses through its service territory. The development of this advanced metering infrastructure is to be accomplished in three phases: the initial design phase to develop the new generation of advanced metering systems (Phase I), which was completed in 2006; the pre-deployment phase (Phase II) to field test and select EdisonSmartConnecttm technologies, select the deployment vendor and finalize the EdisonSmartConnecttm business case for full deployment, which will be conducted during 2007; and the final deployment phase (Phase III), which is expected to begin in 2008 and be completed in 2012. The total cost for this project is estimated to be $1.7 billion of which $1.3 billion is estimated to be capitalized and included in utility rate base.

On July 26, 2007, the CPUC unanimously approved $45 million for Phase II of this project. SCE filed its Phase III application on July 31, 2007, requesting CPUC authorization to deploy EdisonSmartConnecttm meters to all residential and small business customers under 200 kW over a five-year period beginning in 2008. SCE expects a decision on the Phase III application by mid-2008.

Peaker Plant Generation Projects

On August 15, 2006, the CPUC issued a ruling addressing electric reliability needs in Southern California for the summer of 2007 and directing, among other things, that SCE pursue new utility-owned peaker generation (which would be available on notice during peak demand periods) that would be online by August 2007. SCE completed the construction of and placed online four combustion turbine peaker plants, in August 2007, each with a capacity of approximately 45 MW. SCE continues to pursue permitting for the construction of a fifth project. See “Regulatory Matters—Peaker Plant Generation Project” for further discussion.

LIQUIDITY

Overview

As of June 30, 2007, SCE had cash and equivalents of $91 million ($86 million of which was held by SCE’s consolidated VIEs). As of June 30, 2007, long-term debt, including current maturities of long-term debt, was $5.4 billion. On February 23, 2007, SCE amended its credit facility, increasing the amount of borrowing capacity to $2.5 billion, extending the maturity to February 2012 and removing the first mortgage bond security pledge. As a result of removing the first mortgage bond security, the credit facility’s pricing changed to an unsecured basis per the terms of the credit facility agreement. At June 30, 2007, the credit facility supported $179 million in letters of credit and $175 million in commercial paper leaving $2.1 billion available for liquidity purposes.

SCE’s estimated cash outflows during the 12-month period following June 30, 2007 primarily consist of:

•

Debt maturities of approximately $311 million, including $130 million of rate reduction notes that have a separate nonbypassable recovery mechanism approved by state legislation and CPUC decisions. The rate reduction notes are scheduled to be paid off in December 2007 and the nonbypassable rates being charged to customers are expected to cease as of January 1, 2008;

•

Projected capital expenditures of $1.4 billion remaining for 2007 primarily to replace and expand distribution and transmission infrastructure and construct and replace major components of generation assets (see “—Capital Expenditures” below);

•

Dividend payments to SCE’s parent company. On February 22, 2007, the Board of Directors of SCE declared a $25 million dividend to Edison International which was paid in April 2007. On April 26, 2007 the Board of Directors of SCE declared a $25 million dividend which was paid to Edison International in July 2007;

•

Fuel and procurement-related costs (see “Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings”); and

•

General operating expenses.

SCE expects to meet its continuing obligations, including cash outflows for operating expenses, including power-procurement, through cash and equivalents on hand, operating cash flows and short-term borrowings, when necessary. Projected capital expenditures are expected to be financed through operating cash flows and the issuance of short-term and long-term debt and preferred equity.

SCE’s liquidity may be affected by, among other things, matters described in “Regulatory Matters” and “Commitments, Guarantees and Indemnities.”

Capital Expenditures

As discussed under the heading “Liquidity—Capital Expenditures” in the year-ended 2006 MD&A, SCE is experiencing significant growth in actual and planned capital expenditures to replace and expand its distribution and transmission infrastructure, and to construct and replace major components of generation assets. On February 22, 2007, the Finance Committee of the Board of Directors approved SCE’s 2007 through 2011 capital investment plan which includes total capital spending of up to $17.3 billion. During the three- and six-month periods ended June 30, 2007, SCE spent $550 million and $1 billion, respectively, in capital expenditures related to its 2007 capital plan.

Credit Ratings

At June 30, 2007, SCE’s credit ratings were as follows:


	Moody’s Rating	S&P Rating	Fitch Rating
Long-term senior secured debt	A2	BBB+	A+
Short-term (commercial paper)	P-2	A-2	F-1

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 (see “Edison International (Parent): Liquidity” for further discussion). 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 determines compliance with this capital structure based on a 13-month weighted-average calculation. At June 30, 2007, SCE’s 13-month weighted-average common equity component of total capitalization was 49.85%. At June 30, 2007, SCE had the capacity to pay $216 million in additional dividends based on the 13-month weighted-average method. However, based on recorded June 30, 2007 balances, SCE’s

common equity to total capitalization ratio (as adjusted for rate-making purposes) was 50.60%. SCE had the capacity to pay $303 million of additional dividends to Edison International based on June 30, 2007 recorded balances.

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, 2007, SCE’s debt to total capitalization ratio was 0.44 to 1.

Margin and Collateral Deposits

SCE has entered into certain margining agreements for power and gas trading activities in support of its procurement plan as approved by the CPUC. SCE’s margin deposit requirements under these agreements can vary depending upon the level of unsecured credit extended by counterparties and brokers, changes in market prices relative to contractual commitments, and other factors. At June 30, 2007, SCE had a net deposit of $175 million (consisting of $36 million in cash and reflected in “Margin and collateral deposits” on the consolidated balance sheet and $139 million in letters of credit) with counterparties. In addition, SCE has deposited $59 million (consisting of $18 million in cash and reflected in “Margin and collateral deposits” on the consolidated balance sheet and $40 million in letters of credit) with other brokers. Cash deposits with brokers and counterparties earn interest at various rates.

CURRENT REGULATORY DEVELOPMENTS

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

Impact of Regulatory Matters on Customer Rates

SCE is concerned about high customer rates, which were a contributing factor that led to the deregulation of the electric services industry during the mid-1990s. On January 1, 2007 SCE’s bundled service system average rate was 14.5¢ per-kWh (including 3.1¢ per-kWh related to CDWR which is not recognized as revenue by SCE). On February 14, 2007, SCE’s system average rate decreased to 13.9¢-per-kWh (including 3.0¢ per-kWh related to CDWR) mainly as the result of estimated lower natural gas prices in 2007, as well as the refund of overcollections in the ERRA balancing account that occurred in 2006 from lower than expected natural gas prices and higher than expected summer 2006 kWh sales (see “—Energy Resource Recovery Account Proceedings” below). In addition, the rate change incorporates the collection of the residential rate increase deferral discussed in the year-ended 2006 MD&A under the heading “Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates.”

On August 1, 2007, SCE filed its 2008 ERRA forecast requesting a revenue requirement increase of $515 million (see “—Energy Resource Recovery Account Proceedings”). In addition, SCE requested to consolidate other rate changes authorized by the CPUC with this ERRA revenue requirement increase effective on or soon after January 1, 2008. SCE is estimating an increase of $528 million in its total system 2008 consolidated revenue requirement when combining the ERRA revenue requirement increase with all other estimated CPUC-authorized revenue requirement changes. After taking estimated 2008 sales growth into account, SCE estimates a total system revenue increase of $447 million. Implementation of the increased consolidated revenue requirement, as requested, would increase the bundled service system average rate from 13.9¢-per-kWh (including 3.0¢ per-kWh related to CDWR) to 14.4 ¢-per-kWh (including 3.1¢ per-kWh related to CDWR), an increase of 3.6%.

FERC Petition for Transmission Incentives

On May 18, 2007, SCE filed a petition seeking transmission incentives for three of its largest proposed transmission projects; Devers-Palo Verde II (“DPV2”) (a high voltage (500 kV) transmission line from Devers substation near Palm Springs, California to a new substation near Palo Verde, west of Phoenix), the Tehachapi

Transmission Project (“Tehachapi”) (an eleven transmission line segments and associated substations project to interconnect renewable generation projects near the Tehachapi and Big Creek area), and the Rancho Vista Substation project (“Rancho Vista”) (a proposed new 500kV substation in the City of Rancho Cucamonga). In its Petition, SCE requested a higher return on equity on SCE’s entire transmission rate base in SCE’s next FERC transmission rate case and an additional increase for these three projects upon approval of SCE’s incentive filing. In addition, the petition requests to include in rate base 100% of prudently-incurred capital expenditures during the construction of all three projects 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. On July 17, 2007, the FERC requested further information relating to SCE’s incentives request. SCE must provide this information by August 16, 2007. A FERC ruling on the petition is not likely to be issued before September, 2007.

The Tehachapi and Rancho Vista projects are proceeding as anticipated. However, despite SCE having obtained approvals for the DPV2 project from the CPUC and other Arizona governmental agencies, by decision dated June 6, 2007, the Arizona Corporation Commission (ACC) denied approval of the DPV2 project. SCE’s application for rehearing and reconsideration was subsequently denied due to inaction by the ACC. SCE intends to file an appeal of the ACC’s decision by August 14, 2007 and is evaluating its options, which include filing a new application with the ACC and building the project in various phases. As of June 30, 2007, SCE has spent approximately $28 million on this project.

Energy Resource Recovery Account Proceedings

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings” in the year-ended 2006 MD&A, the ERRA is the balancing account mechanism to track and ensure recovery of SCE’s fuel and procurement-related costs. At December 31, 2006, the ERRA was overcollected by $526 million, which was 13.2% of SCE’s prior year’s generation revenue. On January 25, 2007, the CPUC approved SCE’s request to reduce the 2007 ERRA revenue requirement by $630 million. The CPUC also authorized SCE to consolidate the decreased ERRA revenue requirement with the authorized revenue requirement changes in other SCE proceedings resulting in lower rate levels implemented in February 2007. See “—Impact of Regulatory Matters on Customer Rates” above for further discussion. At June 30, 2007 the ERRA was overcollected by $507 million. SCE anticipates this overcollection to continue to decrease during the remainder of 2007, based on the reduced ERRA revenue requirement approved by the CPUC on January 25, 2007.

2008 ERRA Forecast

On August 1, 2007, SCE filed its 2008 ERRA forecast application in which it forecasts an ERRA revenue requirement of $4.3 billion, an increase of $515 million over SCE’s adopted 2007 ERRA revenue requirement. The increase is mainly attributable to a reduction in ERRA overcollections resulting from the $630 million revenue requirement reduction in 2007, as discussed above. See “—Impact of Regulatory Matters on Customer Rates” above for further discussion.

ISO Disputed Charges

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—ISO Disputed Charges” in the year-ended 2006 MD&A, on April 20, 2004, the FERC issued an order 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 March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. On May 25, 2007, the FERC issued a procedural order granting the rehearing application for the purpose of allowing the FERC to give it further consideration. In a future order, FERC may deny the rehearing request or grant the requested relief in whole or in part. SCE believes that the most recent substantive FERC order correctly allocates responsibility for these ISO charges. However, SCE cannot provide assurance as to the final outcome of the rehearing. 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, SCE may seek recovery in its reliability service rates. SCE cannot provide any assurance that recovery of these charges in its reliability service rates would be permitted.

Peaker Plant Generation Projects

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—Peaker Plant Generation Projects” in the year-ended 2006 MD&A, SCE pursued construction of five combustion turbine peaker plants. In August 2007, four of these peaker plants were placed online. SCE continues the construction of the fifth project, however, the required construction permit has been denied by the City of Oxnard. SCE believes the permit denial to be without merit and is appealing this denial to the Coastal Commission and expects a decision in the fourth quarter of 2007. However, SCE cannot predict the outcome of the proceeding nor estimate the impact of a delayed permit issuance on the project’s construction schedule. SCE believes that the peaker plants will help meet electric reliability needs, notwithstanding the delay encountered by the fifth Oxnard project. SCE has revised its initial budget for all five projects from $250 million to approximately $275 million. SCE expects to fully recover its costs from these projects, but cannot predict the outcome of regulatory proceedings. As of June 30, 2007 SCE had spent or firmly committed approximately $179 million.

Procurement of Renewable Resources

Scheduling Coordinator Tariff Dispute

Pursuant to the Amended and Restated Exchange Agreement, SCE serves as a scheduling coordinator for the DWP over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund for FERC-authorized scheduling coordinator charges incurred by SCE on the DWP’s behalf. The scheduling coordinator charges are billed to the DWP under a FERC tariff that remains subject to dispute. The DWP has paid the amounts billed under protest but requested that the FERC declare that SCE was obligated to serve as the DWP’s scheduling coordinator without charge. The FERC accepted SCE’s tariff for filing, but held that the rates charged to the DWP have not been shown to be just and reasonable and thus made them subject to refund and further review by the FERC. In September 2006, SCE and the DWP agreed to a term sheet that would settle this dispute, among others surrounding the Exchange Agreement. The settlement was approved by the FERC on July 27, 2007 and is expected to be approved by the City of Los Angeles in the second half of 2007. As of June 30, 2007, SCE has an accrued liability of $47 million (including $6 million of interest) for the potential refunds representing charges collected. Under the settlement terms, SCE would refund to the DWP the scheduling coordinator charges collected, with an offset for contract losses, and will be able to recover the scheduling coordinator charges from all transmission grid customers.

FERC Refund Proceedings

In 2006, SCE received distributions of approximately $55 million on its allowed bankruptcy claim. In April 2007, SCE received and recorded an additional distribution on its allowed bankruptcy claim of approximately $12 million and 55,465 shares of Portland General Electric Company stock, with an aggregate value of less than $2 million. Additional distributions are expected but SCE cannot currently predict the amount or timing of such distributions.

Investigations Regarding Performance Incentives Rewards

SCE conducted investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings of misconduct and misreporting as further discussed below.

Customer Satisfaction

Employee Injury and Illness Reporting

System Reliability

CPUC Investigation

Palo Verde Nuclear Generating Station Outage and Inspection

of reduced power operation of approximately $32 million are expected to be recovered through the ERRA rate-making mechanism.

OTHER DEVELOPMENTS

Environmental Matters

SCE is subject to numerous federal and state environmental laws and regulations, which require them 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. SCE believes that its operating affiliates are in substantial compliance with existing environmental regulatory requirements.

SCE’s power plants, in particular their coal-fired plants, may be affected by recent developments in federal and state environmental laws and regulations. These laws and regulations, including those relating to SO₂ and NO_x emissions, mercury emissions, ozone and fine particulate matter emissions, regional haze, water quality, and climate change, may require significant capital expenditures at these facilities. These laws and regulations will continue to be monitored to assess what implications, if any, they will have on the operation of domestic power plants owned or operated by SCE, or the impact on SCE’s results of operations or financial position.

For a discussion of SCE’s environmental matters, refer to “Other Developments—Environmental Matters” in the year-ended 2006 MD&A. There have been no significant developments with respect to environmental matters affecting SCE since the filing of SCE’s Annual Report on Form 10-K, except as follows:

Climate Change

In September 2006, California’s Governor Schwarzenegger signed two bills into law regarding GHG emissions. The first, known as AB 32 or the California Global Warming Solutions Act of 2006, establishes a comprehensive program of regulatory and market mechanisms to achieve reductions of GHG emissions. AB 32 requires the California Air Resources Board to develop regulations and market mechanisms targeted to reduce California’s GHG emissions to 1990 levels by 2020. California Air Resources Board’s mandatory program will take effect commencing 2012 and will implement incremental reductions so that GHG emissions will be reduced to 1990 levels by 2020. The second bill, known as SB 1368, relates specifically to power generation and requires the CPUC and the CEC to adopt GHG performance standards for investor owned and publicly owned utilities, respectively, for long-term procurement of electricity. The standards must equal the performance of a combined-cycle gas turbine generator. The CPUC adopted such a standard on January 25, 2007 (which limits emissions to 1,100 pounds of carbon dioxide per MWh). On May 28, 2007, the CEC adopted regulations pursuant to SB 1368 establishing and implementing a GHG EPS for baseload generation of local publicly owned electric utilities. These regulations were submitted to the Office of Administrative Law on June 1, 2007 and were subsequently

disapproved. The CEC conducted public workshops to collect comments and draft new proposed language to address the Office of Administrative Law’s concerns. In addition, the CPUC is addressing climate change related issues in various regulatory proceedings. In a decision dated May 25, 2007, the CPUC expanded the scope of its GHG rulemaking to include GHG emissions associated with the transmission, storage, and distribution of natural gas in California, in addition to the combustion of natural gas by non-electricity generator end-use customers. SCE will continue to monitor the federal and state developments relating to regulation of GHG emissions to determine their impacts on SCE’s operations. Requirements to reduce emissions of CO₂ and other GHG emissions could significantly increase SCE’s cost of generating electricity from fossil fuels, especially coal, as well as the cost of purchased power, which are generally borne by SCE’s customers.

Environmental Remediation

As of June 30, 2007, SCE’s recorded estimated minimum liability to remediate its 23 identified sites was $74 million. The ultimate costs to clean up SCE’s identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $127 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 32 immaterial sites whose total liability ranges from $2 million (the recorded minimum liability) to $8 million.

Federal and State Income Taxes

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

As discussed in the year-ended 2006 MD&A, SCE is exposed to commodity price risk associated with its purchases for additional capacity and ancillary services to meet its peak energy requirements as well as exposure to natural gas prices associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including the Mountainview plant.

SCE has an active hedging program in place to minimize ratepayer exposure to spot-market price spikes; 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 spot-market prices, SCE enters into energy options, tolling arrangements, and forward physical contracts. In the first quarter of 2007 SCE secured FTRs through the annual ISO auction. These FTRs provide SCE with scheduling priority in certain transmission grid congestion areas in the day-ahead market and qualify as derivative instruments. 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. Certain derivative instruments do not meet the normal purchases and sales exception because demand variations and CPUC mandated resource adequacy requirements may result in physical delivery of excess energy that may not be in quantities that are expected to be used over a reasonable period in the normal course of business and may then be resold into the market. In addition, certain contracts do not meet the definition of clearly and closely related under SFAS No. 133 since pricing for certain renewable contracts is based on an unrelated commodity. The derivative instrument fair values are marked to market at each reporting period. Any fair value changes for recorded derivatives are recorded in purchased-power expense and offset through the provision for regulatory adjustment clauses – net; therefore, fair value changes do not affect earnings. Hedge accounting is not used for these transactions due to this regulatory accounting treatment. 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, 2007				December 31, 2006
In millions	Assets		Liabilities		Assets		Liabilities
Energy options	$	—	$	24	$	—	$	10
FTRs		89		—		—		—
Forward physicals (power) and tolling arrangements		15		—		—		1
Gas options, swaps and forward arrangements		—		20		—		101
Total	$	104	$	44	$	—	$	112

Quoted market prices, if available, are used for determining the fair value of contracts, as discussed above. If quoted market prices are not available, internally maintained standardized or industry accepted models are used to determine the fair value. The models are updated with spot prices, forward prices, volatilities and interest rates from regularly published and widely distributed independent sources.

The increase for the six months ended June 30, 2007 in net unrealized gains on economic hedging activities was primarily a result of changes in SCE’s gas hedge portfolio mix. Due to expected recovery through regulatory mechanisms unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings.

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.

Results of Operations

Net Income Available for Common Stock

SCE’s net income available for common stock was $144 million and $325 million for the three- and six-month periods ended June 30, 2007, compared to $234 million and $355 million for the respective periods in 2006. SCE’s quarter and year-to-date earnings decreased due to an $81 million benefit from the resolution of an outstanding issue involving a portion of revenue collected during 2001 – 2003 related to state income taxes recorded in 2006. The second quarter earnings also decreased by $9 million primarily due to the catch-up adjustment upon receipt of the 2006 GRC decision in May 2006, which was effective back to January 12, 2006, partially offset by the favorable resolution of an outstanding state income tax issue. The year-to-date decrease was partially offset by a $31 million tax benefit primarily reflecting progress on an appeal with the IRS related to the income tax treatment of costs associated with environmental remediation recorded in 2007 and increased earnings of approximately $20 million mainly due to higher revenue associated with the 2006 GRC decision and lower income taxes from the favorable resolution of an outstanding state income tax issue.

Operating Revenue

The following table sets forth the major changes in operating revenue:


In millions	Three Months Ended June 30, 2007 vs. 2006			Six Months Ended June 30, 2007 vs. 2006
Electric utility revenue
Rate changes and impact of tiered rate structure (including unbilled)	$	(148	)	$	(29	)
Sales volume changes (including unbilled)		(2	)		71
Balancing account over/under collections		30			(98	)
Sales for resale		42			11
SCE’s VIEs		25			1
Other (including inter company transactions)		(8	)		(13	)
Total	$	(61	)	$	(57	)

SCE’s retail sales represented approximately 87% of electric utility revenue for both the three- and six-month periods ended June 30, 2007, respectively, compared to approximately 89% for both comparable periods in 2006. Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is generally significantly higher than other quarters.

Total electric utility revenue decreased by $61 million and $57 million for the three- and six-month periods ended 2007, respectively (as shown in the table above). The variances for the revenue components are as follows:

•

Electric utility revenue from rate changes decreased for the three- and six-month periods ended June 30, 2007, mainly due to the impact of warmer weather experienced in the later part of second quarter of 2006 resulting in increased volumes sold at a higher rate due to SCE’s tiered rate structure. The year-to-date decrease was partially offset by increased rates in early 2007, compared to the same period in 2006. Effective February 14, 2007, SCE’s system average rate decreased to 13.9¢-per-kWh (including 3.0¢ per-kWh related to CDWR) mainly as the result of estimated lower natural gas prices in 2007, as well as the refund of overcollections in the ERRA balancing account that occurred in 2006 from lower than expected

natural gas prices and higher than expected summer 2006 kWh sales (see “Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates,” and “—Energy Resource Recovery Account Proceedings” for further discussion of these rate changes);

•

Electric utility revenue resulting from sales volume changes for the six months ended 2007 was mainly due to an increase in customer growth, partially offset by decreased sales volume resulting from the warmer weather experienced in the later part of second quarter of 2006;

•

SCE recognizes revenue, subject to balancing account treatment, equal to the amount of the actual costs incurred and up to its authorized revenue requirement. Any revenue collected in excess of actual costs incurred or above the authorized revenue requirement is not recognized as revenue and is deferred and recorded as regulatory liabilities to be refunded in future customer rates. Costs incurred in excess of revenue billed are deferred in a balancing account and recorded as regulatory assets for recovery in future customer rates. Balancing account over/undercollections represent these differences. For the three- and six-month periods ended June 30, 2007, SCE collected revenue in excess of actual costs incurred and as a result deferred approximately $44 million and $65 million, respectively. For the three months ended June 30, 2006, SCE collected revenue in excess of actual costs incurred and as a result deferred approximately $74 million, and for the six months ended June 30, 2006, SCE recognized approximately $34 million of revenue. The variance is mainly due to the impact of overcollections in 2006;

•

Electric utility revenue from sales for resale represents the sale of excess energy. Excess energy from SCE sources which may exist at certain times is resold in the energy markets. Sales for resale revenue increased due to higher excess energy in 2007, compared to the same periods in 2006. Revenue from sales for resale is refunded to customers through the ERRA balancing account and does not impact earnings; and

•

SCE’s VIEs revenue represents the recognition of revenue resulting from the consolidation of four gas-fired power plants where SCE is considered the primary beneficiary. These VIEs affect SCE’s revenue, but do not affect earnings; the increase in revenue from SCE’s VIEs during the second quarter of 2007 was primarily due to payments received in settlement of claims related to natural gas purchase contracts, a planned outage at one of the projects in 2006, partially offset by lower volumes sold in 2007 for one of the projects.

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 none of these collections are recognized as revenue by SCE. These amounts were $503 million and $1.1 billion for the three- and six-month periods ended June 30, 2007, respectively, compared to $553 million and $1.1 billion for the same respective periods in 2006.

Operating Expenses

Fuel Expense

SCE’s fuel expense increased $48 million and $47 million for the three- and six-month periods ended June 30, 2007, respectively, as compared to the same periods in 2006. The quarter and year-to-date increases were mainly due to higher fuel expense at Mountainview of $20 million and $40 million for the three- and six-month periods ended June 30, 2007, respectively, due in part to an increase in natural gas prices. Also contributing to the increases was higher nuclear fuel expense of $10 million and $20 million, for the three- and six-month periods ended June 30, 2007, respectively, resulting primarily from a planned refueling and maintenance outage at SCE’s San Onofre Unit 2 in 2006. The quarter increase also reflects higher fuel expense of $25 million primarily related to one of the SCE VIE projects driven by a planned outage that occurred during the second quarter of 2006.

Purchased-Power Expense

The following is a summary of purchased-power expense:


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2007			2006			2007			2006
Purchased-power from bilateral contracts, QFs, ISO, and exchange energy	$	787		$	706		$	1,237		$	1,321
Unrealized (gains) / losses on economic hedging activities		45			9			(89	)		342
Realized (gains) / losses on economic hedging activities		23			91			52			166
Energy settlements and refunds		(26	)		(37	)		(54	)		(46	)
Total purchased-power expense	$	829		$	769		$	1,146		$	1,783

Purchased-power expense increased $60 million for the three months ended June 30, 2007 and decreased $637 million for the six months ended June 30, 2007, as compared to the same periods in 2006. The increase for the three months ended June 30, 2007 was mainly due to higher QF purchased-power expense of approximately $60 million resulting from an increase in the average spot natural gas prices (as discussed further below), higher costs for ISO-related energy purchases of $30 million, and higher net unrealized losses on economic hedging activities of $36 million, primarily due to lower forward natural gas prices in the second quarter of 2007, compared to the same period in 2006. Due to expected recovery through regulatory mechanisms, unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings. The quarter variance reflects net realized losses on economic hedging activities of $23 million for the three months ended June 30, 2007 compared to net realized losses of $91 million for the same period in 2006. The year-to-date variance reflects net realized losses of $52 million for the six months ended June 30, 2007 compared to net realized losses of $166 million for the same period in 2006. The year-to-date variance reflects net unrealized gains on economic hedging activities of $89 million, compared to net unrealized losses on economic hedging activities of $342 million for the same period in 2006 (see “Market Risk Exposures—Commodity Price Risk” for further discussion). The changes in net unrealized (gains)/losses primarily resulted from changes in SCE’s gas hedge portfolio mix. In addition, the year-to-date decrease was due to lower ISO-related purchases of approximately $80 million resulting from lower kWh purchases, and lower firm related purchases of approximately $30 million.

Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated prices. Energy payments to gas-fired QFs are generally tied to spot natural gas prices. Energy payments for most renewable QFs are at a fixed price of 5.37¢-per-kWh. In late 2006, certain renewable QF contracts were amended and energy payments for these contracts are at a fixed price of 6.15¢-per-kWh, effective May 2007.

Provisions for Regulatory Adjustment Clauses – Net

Provisions for regulatory adjustment clauses – net decreased $23 million and increased $626 million for the three- and six-month periods ended June 30, 2007, respectively, as compared to the same periods in 2006. The quarter and year-to-date variances reflect net unrealized losses on economic hedging activities of $45 million and $9 million for three-month periods ended June 30, 2007 and 2006, respectively, and net unrealized gains on economic hedging activities of approximately $89 million for the six-month period ended June 30, 2007, compared to $342 million of net unrealized losses for the same period last year (mentioned above in purchased-power expense). The quarter and year-to-date variances also reflect the resolution of a $135 million one-time gain related to a portion of revenue collected during the 2001 – 2003 period related to state income taxes recorded in the second quarter of 2006. The quarter decrease also reflects a change from net overcollections in 2006 to net undercollections for the same period in 2007 of $175 million primarily related to lower revenue resulting from the impact of warmer weather experienced in the later part of the second quarter of 2006 and lower rates. The year-to-date increase also reflects lower net undercollections of purchased-power, fuel, and operation and maintenance expense of approximately $15 million resulting from higher sales and lower

procurement costs for the six-month period ended June 30, 2007, compared to the same period in 2006 (see “Regulatory Matters—Current Regulatory Developments—Impacts of Regulatory Matters on Customer Rates,” and “Energy Resource Recovery Account Proceedings” for further discussion of these rate changes).

Other Operation and Maintenance Expense

SCE’s other operation and maintenance expense increased $22 million and $8 million for the three- and six-month periods ended June 30, 2007, respectively, as compared to the same periods in 2006. The quarter and year-to-date increases were mainly due to higher demand-side management and energy efficiency costs of approximately $35 million and $60 million for the three- and six-month periods ended June 30, 2007, respectively, (which are recovered through regulatory mechanisms approved by the CPUC) and higher benefit-related costs of $15 million for both the quarter and year-to-date periods. These increases were partially offset by lower must-run and must-offer obligation costs of $30 million and $40 million for the three- and six-month periods ended June 30, 2007 related to the reliability of the California ISO systems and higher generation-related costs of approximately $30 million for the six months ended June 30, 2007 resulting from the planned refueling and maintenance outages at SCE’s San Onofre Units 2 and 3 in the first quarter 2006. As a result of implementation of the 2006 GRC, beginning in May 2006, costs related to Mohave shutdown, postretirement benefits other than pensions and results sharing are being recovered through a balancing account mechanism.

Depreciation, Decommissioning and Amortization Expense

SCE’s depreciation, decommissioning and amortization expense decreased $29 million and $6 million for the three- and six-month periods ended June 30, 2007, respectively, compared to the same periods in 2006 primarily related to depreciation related to transmission and distribution assets and SCE’s decommissioning trusts.

The depreciation expense related to SCE’s transmission and distribution assets decreased approximately $15 million and increased $15 million for the three- and six-month periods ended June 30, 2007, respectively. The quarter decrease was mainly due to the implementation of the new depreciation rates approved in the 2006 GRC decision for the period January 12, 2006 through May 31, 2006 which resulted in increased depreciation expense recorded in the second quarter of 2006. The quarter and year-to-date variances reflect increased depreciation expense resulting from additions to transmission and distribution assets.

SCE’s decommissioning expense decreased $5 million and $20 million for the three- and six-month periods ended June 30, 2007, respectively, compared to the same periods in 2006. The decrease primarily resulted from other-than-temporary impairment losses associated with the nuclear decommissioning trust funds, which, due to its regulatory treatment, are recorded in electric utility revenue and are offset in decommissioning expense. As a result, these investment earnings have no impact on net income.

Other Income and Deductions

Interest income

SCE’s interest income decreased $5 million and $9 million for the three- and six-month periods ended June 30, 2007, respectively, compared to the same periods in 2006, mainly due to lower interest income resulting from lower balancing account undercollections in 2007, as compared to 2006.

Other Nonoperating Income

SCE’s other nonoperating income increased $6 million and decreased $5 million for the three- and six-month periods ended June 30, 2007, compared to the same periods in 2006. The variance was mainly due to an in increase in allowance for funds used during construction – equity of approximately $3 million and $10 million for the three- and six-month periods ended June 30, 2007, respectively, resulting from an increase in construction work in progress due to planned capital expenditures (see “Liquidity—Capital Expenditures” for further

discussion). The year-to-date increase was offset by an incentive reward in 2006 related to the efficient operation of Palo Verde compared to no incentive rewards in 2007 as a result of the incentive program ending in 2006. The incentive reward approved by the CPUC for the efficient operation of Palo Verde was $13 million in the first quarter of 2006.

Interest Expense – Net of Amounts Capitalized

SCE’s interest expense – net of amounts capitalized increased $3 million and $14 million for the three- and six-month periods ended June 30, 2007, respectively, mainly due to higher interest expense on balancing account overcollections in 2007, as compared to 2006. The increase was also due to higher interest expense on long-term debt resulting from higher balances outstanding as of June 30, 2007, compared to the same period in 2006.

Income Tax Expense

SCE’s composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. SCE’s effective tax rate from operations was 28% and 25% for the three- and six-month periods ended June 30, 2007, respectively, as compared to 37% and 38% for the respective periods in 2006. The decreased effective tax rate was primarily caused by reductions made to the income tax reserves during the first quarter of 2007 to reflect progress in an administrative appeal process with the IRS related to the income tax treatment of costs associated with environmental remediation and also due to reductions made to the income tax reserve during the second quarter of 2007 to reflect settlement of a state tax issue related to the April 2007 State Notice of Proposed Adjustment discussed below. Additional decreases to the 2007 effective tax rate resulted from accruing lower tax reserve interest expense in 2007 as compared to 2006 as a result of implementing FIN 48 and from year over year changes in property related flow-through items. In addition, the decreased effective tax rate in the second quarter of 2007 resulted from a reduction in pre-tax income.

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 was $1.3 billion for the six-month period ended June 30, 2007, compared to $767 million for the comparable period in 2006. The 2007 change in cash provided by operating activities was primarily due to the timing of cash receipts and disbursements related to working capital items.

Cash Flows from Financing Activities

Cash provided (used) by financing activities from continuing operations mainly consisted of long-term and short-term debt issuances (payments) at SCE.

Financing activities in 2007 were as follows:

•

During the first half of 2007 SCE’s net issuances of commercial paper classified as short-term debt was $175 million;

•

Financing activities in 2007 include dividend payments of $85 million paid to Edison International;

Financing activities in 2006 included activities related to the rebalancing of SCE’s capital structure:

•

In January 2006, SCE issued $500 million of first and refunding mortgage bonds which consisted of $350 million of 5.625% bonds due in 2036 and $150 million of floating rate bonds due in 2009. The proceeds from this issuance were used in part to redeem $150 million of variable rate first and refunding mortgage bonds due in January 2006 and $200 million of its 6.375% first and refunding mortgage bonds due in January 2006;

•

In January 2006, SCE issued two million shares of 6% Series C preference stock (noncumulative, $100 liquidation value) and received net proceeds of $196 million;

•

In April 2006, SCE issued $331 million of tax-exempt bonds which consisted of $196 million of 4.10% bonds which are subject to remarketing in April 2013 and $135 million of 4.25% bonds which are subject to remarketing in November 2016. The proceeds from this issuance were used to call and redeem $196 million of tax-exempt bonds due February 2008 and $135 million of tax-exempt bonds due March 2008. This transaction was treated as a noncash financing activity; and

•

Financing activities in 2006 include dividend payments of $131 million paid to Edison International.

Cash Flows from Investing Activities

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

Investing activities in 2007 reflect $1.1 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $28 million for nuclear fuel acquisitions.

Investing activities in 2006 reflect $1.1 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $50 million for nuclear fuel acquisitions and approximately $8 million related to the Mountainview plant.

NEW ACCOUNTING PRONOUNCEMENTS

Accounting Pronouncement Adopted

In July 2006, the FASB issued FIN 48 which clarifies the accounting for uncertain tax positions. FIN 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. SCE adopted FIN 48 effective January 1, 2007. Implementation of FIN 48 resulted in a cumulative-effect adjustment that increased retained earnings by $213 million upon adoption. SCE will continue to monitor and assess new income tax developments.

Accounting Pronouncements Not Yet Adopted

COMMITMENTS AND INDEMNITIES

Fuel Supply Contracts

SCE entered into service contracts associated with uranium enrichment and fuel fabrication during the first six months of 2007. As a result, SCE’s fuel supply commitments for the remainder of 2007 are estimated to be $143 million.

Operating and Capital Leases

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

Item 4.

Controls and Procedures

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION

Item 4.

Submission of Matters to a Vote of Security Holders

At SCE’s Annual Meeting of Shareholders on April 26, 2007, 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 and voted on the ratification of the appointment of the independent public accounting firm. 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	Witheld
John E. Bryson	457,775,182	218,178
Vanessa C.L. Chang	457,747,468	245,892
France A. Córdova	457,782,922	210,438
Charles B. Curtis	457,774,996	218,364
Alan J. Fohrer	457,790,422	202,938
Bradford M. Freeman	457,776,322	217,038
Luis G. Nogales	457,747,240	246,120
Ronald L. Olson	457,779,448	213,912
James M. Rosser	457,776,766	216,594
Richard T. Schlosberg, III	457,775,188	218,172
Robert H. Smith	457,743,802	249,558
Thomas C. Sutton	457,778,500	214,860

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


For	Against	Abstentions	Broker Non-Votes
457,790,620	109,488	93,252	0

Item 6.

Exhibits

Southern California Edison Company


10.1		Edison International 2007 Director Compensation Schedule, as adopted June 29, 2007 (File No. 1-9936, filed as Exhibit 10.1 to Edison International’s Form 10-Q for the quarter ended June 30, 2007)*

10.2		Edison International Director Matching Gifts Program, as adopted June 29, 2007 (File No. 1-9936, filed as Exhibit 10.2 to Edison International’s Form 10-Q for the quarter ended June 30, 2007)*

10.3		Executive Retirement Plan amendment 2005-1, effective December 14, 2005 (File No. 1-9936, filed as Exhibit 10.3 to Edison International’s Form 10-Q for the quarter ended June 30, 2007)*

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

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

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
		Vice President and Controller
		(Duly Authorized Officer and
		Principal Accounting Officer)

Dated: August 9, 2007