SOUTHERN CALIFORNIA EDISON Co - Quarter Report: 2006 March (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 March 31, 2006

¨	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 April 30, 2006
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 Months Ended March 31, 2006 and 2005	1

		Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2006 and 2005	1

		Consolidated Balance Sheets – March 31, 2006 and December 31, 2005	2

		Consolidated Statements of Cash Flows – Three Months Ended March 31, 2006 and 2005	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	35

	Item 4.	Controls and Procedures	35

Part II.	Other Information:

	Item 6.	Exhibits	36

	Signature		37

SOUTHERN CALIFORNIA EDISON COMPANY

PART I FINANCIAL INFORMATION

Item 1. Financial Statements

CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended March 31,
In millions	2006			2005
	(Unaudited)
Operating revenue	$	2,217		$	1,908
Fuel		311			255
Purchased power		1,013			388
Provisions for regulatory adjustment clauses – net		(363	)		65
Other operation and maintenance		617			601
Depreciation, decommissioning and amortization		253			222
Property and other taxes		54			49
Total operating expenses		1,885			1,580
Operating income		332			328
Interest and dividend income		15			9
Other nonoperating income		27			18
Interest expense – net of amounts capitalized		(97	)		(103	)
Other nonoperating deductions		(11	)		(7	)
Income before tax and minority interest		266			245
Income tax		83			65
Minority interest		50			48
Net income		133			132
Dividends on preferred and preference stock not subject to mandatory redemption		12			1
Net income available for common stock	$	121		$	131

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended March 31,
In millions	2006		2005
	(Unaudited)
Net income	$	133	$	132
Other comprehensive income, net of tax:
Amortization of cash flow hedges		—		1
Comprehensive income	$	133	$	133

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

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS


In millions	March 31, 2006			December 31, 2005
	(Unaudited)
ASSETS
Cash and equivalents	$	142		$	143
Restricted cash		50			57
Margin and collateral deposits		108			178
Receivables, less allowances of $32 and $33 for uncollectible accounts at respective dates		673			849
Accrued unbilled revenue		274			291
Inventory		230			220
Trading and price risk management assets		29			237
Regulatory assets		829			536
Other current assets		74			92
Total current assets		2,409			2,603
Nonutility property – less accumulated provision for depreciation of $585 and $569 at respective dates		1,074			1,086
Nuclear decommissioning trusts		2,984			2,907
Other investments		84			80
Total investments and other assets		4,142			4,073
Utility plant, at original cost:
Transmission and distribution		16,929			16,760
Generation		1,443			1,370
Accumulated provision for depreciation		(4,868	)		(4,763	)
Construction work in progress		1,090			956
Nuclear fuel, at amortized cost		153			146
Total utility plant		14,747			14,469
Regulatory assets		3,023			3,013
Trading and price risk management assets		24			42
Other long-term assets		498			503
Total long-term assets		3,545			3,558

Total assets	$	24,843		$	24,703

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

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS


In millions, except share amounts	March 31, 2006			December 31, 2005
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Short-term debt	$	188		$	—
Long-term debt due within one year		246			596
Accounts payable		687			898
Accrued taxes		254			242
Accrued interest		96			106
Counterparty collateral		30			183
Customer deposits		184			183
Book overdrafts		182			257
Accumulated deferred income taxes – net		168			5
Trading and price risk management liabilities		155			87
Regulatory liabilities		505			681
Other current liabilities		683			723
Total current liabilities		3,378			3,961
Long-term debt		5,107			4,669
Accumulated deferred income taxes – net		2,796			2,815
Accumulated deferred investment tax credits		117			119
Customer advances and other deferred credits		553			550
Trading and price risk management liabilities		118			101
Power-purchase contracts		55			64
Accumulated provision for pensions and benefits		527			500
Asset retirement obligations		2,641			2,621
Regulatory liabilities		3,009			2,962
Other long-term liabilities		280			284
Total deferred credits and other liabilities		10,096			10,016
Total liabilities		18,581			18,646
Commitments and contingencies (Notes 3 and 4)
Minority interest		367			398
Common stock, no par value (434,888,104 shares outstanding at each date)		2,168			2,168
Additional paid-in capital		350			361
Accumulated other comprehensive loss		(16	)		(16	)
Retained earnings		2,464			2,417
Total common shareholder’s equity		4,966			4,930
Preferred and preference stock not subject to mandatory redemption		929			729
Total shareholders’ equity		5,895			5,659

Total liabilities and shareholders’ equity	$	24,843		$	24,703

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

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
In millions	2006			2005
	(Unaudited)
Cash flows from operating activities:
Net income	$	133		$	132
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization		253			222
Other amortization		17			23
Minority interest		50			48
Deferred income taxes and investment tax credits		67			9
Regulatory assets – long-term		38			170
Regulatory liabilities – long-term		(8	)		(70	)
Other assets		22			(64	)
Other liabilities		14			15
Margin and collateral deposits – net of collateral received		(82	)		69
Receivables and accrued unbilled revenue		192			39
Trading and price risk management assets – short-term		208			(104	)
Trading and price risk management liabilities – short-term		68			(10	)
Inventory and other current assets		16			(88	)
Regulatory assets – short-term		(293	)		(294	)
Regulatory liabilities – short-term		(177	)		352
Accrued interest and taxes		2			29
Accounts payable and other current liabilities		(200	)		(50	)
Net cash provided by operating activities		320			428
Cash flows from financing activities:
Long-term debt issued and issuance costs		495			640
Long-term debt repaid		(350	)		(705	)
Issuance of preference stock		196			—
Redemption of preferred stock		—			(4	)
Rate reduction notes repaid		(62	)		(62	)
Short-term debt financing – net		188			202
Change in book overdrafts		(76	)		(38	)
Shares purchased for stock-based compensation		(44	)		(32	)
Proceeds from stock option exercises		14			16
Excess tax benefits related to stock option exercises		6			—
Minority interest		(81	)		(59	)
Dividends paid		(81	)		(1	)
Net cash provided (used) by financing activities		205			(43	)
Cash flows from investing activities:
Capital expenditures		(494	)		(364	)
Proceeds from nuclear decommissioning trust sales		470			645
Purchases of nuclear decommissioning trust investments		(506	)		(669	)
Customer advances for construction and other investments		4			6
Net cash used by investing activities		(526	)		(382	)
Net increase (decrease) in cash and equivalents		(1	)		3
Cash and equivalents, beginning of period		143			122
Cash and equivalents, end of period	$	142		$	125

The accompanying notes are an integral part of these 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 for the periods covered by this quarterly report on Form 10-Q. The results of operations for the period ended March 31, 2006 are not necessarily indicative of the operating results for the full year.

The quarterly report should be read in conjunction with Southern California Edison Company’s (SCE) Annual Report on Form 10-K for the year ended December 31, 2005 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 2005 Annual Report. SCE follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for stock-based compensation (discussed below in “New Accounting Pronouncements”).

Certain prior-period amounts were reclassified to conform to the March 31, 2006 financial statement presentation.

Income Taxes

SCE’s effective tax rate from continuing operations was 38% for the three-month period ended March 31, 2006 as compared to 33% for the three-month period ended March 31, 2005. The increased effective tax rate resulted from reductions made to accrued tax liabilities in 2005 exceeding reductions made to accrued tax liabilities in 2006. The reductions in both periods were made to reflect progress made in settlement negotiations relating to prior-year tax liabilities.

New Accounting Pronouncements

A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. SCE implemented the new standard in the first quarter of 2006 and applied the modified prospective transition method. Under the modified prospective method, the new accounting standard was applied effective January 1, 2006 to the unvested portion of awards previously granted and will be applied to all prospective awards. Prior financial statements were not restated under this method. The new accounting standard resulted in the recognition of expense for all stock-based compensation awards. Prior to January 1, 2006, SCE used the intrinsic value method of accounting, which resulted in no recognition of expense for its stock options.

Prior to adoption of the new accounting standard, SCE presented all tax benefits of deductions resulting from the exercise of stock options as a component of operating cash flows under the caption “Other liabilities” in the consolidated statements of cash flows. The new accounting standard requires the cash flows resulting from the tax benefits that occur from estimated tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. The $6 million excess tax benefit is classified as a financing cash inflow in 2006.

Due to the adoption of this new accounting standard, SCE recorded a cumulative effect adjustment that increased net income by less than $1 million, net of tax, for the three months ended March 31, 2006, mainly to reflect the change in the valuation method for performance shares classified as liability awards and the use of forfeiture estimates.

SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In April 2006, the Financial Accounting Standards Board issued a Staff Position that specifies how a company should determine the variability to be considered in applying the accounting standard for consolidation of variable interest entities. The pronouncement states that such variability shall be determined based on an analysis of the design of the entity, including the nature of the risks in the entity, the purpose for which the entity was created, and the variability the entity is designed to create and pass along to its interest holders. This new accounting guidance is effective prospectively beginning July 1, 2006, although companies may elect early application and/or retrospective application. SCE is currently evaluating the impact of this new accounting pronouncement.

Regulatory Assets and Liabilities

Regulatory assets included in the consolidated balance sheets are:


In millions	March 31, 2006		December 31, 2005
	(Unaudited)
Current:
Regulatory balancing accounts	$	475	$	355
Direct access procurement charges		107		113
Energy derivatives		142		—
Purchased-power settlements		45		53
Other		60		15
		829		536
Long-term:
Flow-through taxes – net		1,141		1,066
Rate reduction notes – transition cost deferral		413		465
Unamortized nuclear investment – net		476		487
Nuclear-related asset retirement investment – net		288		292
Unamortized coal plant investment – net		96		97
Unamortized loss on reacquired debt		318		323
Direct access procurement charges		26		40
Energy derivatives		94		58
Environmental remediation		55		56
Purchased-power settlements		31		39
Other		85		90
		3,023		3,013
Total regulatory assets	$	3,852	$	3,549

SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory liabilities included in the consolidated balance sheets are:


In millions	March 31, 2006		December 31, 2005
	(Unaudited)
Current:
Regulatory balancing accounts	$	299	$	370
Direct access procurement charges		107		113
Energy derivatives		—		136
Other		99		62
		505		681
Long-term:
ARO		630		584
Costs of removal		2,124		2,110
Direct access procurement charges		26		39
Employee benefits plans		229		229
		3,009		2,962
Total regulatory liabilities	$	3,514	$	3,643

Stock-Based Compensation

SCE’s stock-based compensation plans primarily included the issuance of Edison International stock options and performance shares. Edison International usually does not issue new common stock for equity awards earned. 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 performance shares earned. The amount of cash used to settle stock options exercised was $29 million and $24 million for the quarters ended March 31, 2006 and 2005, respectively. The amount of cash used to settle performance shares classified as equity awards was $19 million and $10 million for the quarters ended March 31, 2006 and 2005, respectively. Edison International has approximately 13.8 million shares remaining for future issuance under its stock-based compensation plans, which are described more fully in Note 2.

Prior to January 1, 2006, SCE accounted for these plans using the intrinsic value method. Upon grant, no stock-based compensation cost for stock options was reflected in net income, as the grant date was the measurement date, and all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Previously, stock-based compensation cost for performance shares was remeasured at each reporting period and related compensation expense was adjusted. As discussed in “New Accounting Pronouncements” above, effective January 1, 2006, SCE implemented a new accounting standard that requires companies to use the fair value accounting method for stock-based compensation resulting in the recognition of expense for all stock-based compensation awards. SCE recognizes stock-based compensation expense on a straight-line basis over the vesting period. SCE recognizes stock-based compensation expense for awards granted to retirement-eligible participants as follows: for stock-based awards granted prior to January 1, 2006, SCE recognized stock-based compensation expense over the explicit vesting period and accelerated any remaining unrecognized compensation expense when a participant actually retired; for awards granted or modified after January 1, 2006, to participants who are retirement-eligible or will become retirement-eligible prior to the end of the normal vesting period for the award, stock-based compensation will be recognized on a prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes eligible for retirement. If SCE recognized stock-based compensation expense for awards granted

SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

prior to January 1, 2006, over a period to the date the participant first became eligible for retirement, stock-based compensation expense would have changed by an immaterial amount for the quarters ended March 31, 2006 and 2005.

Total stock-based compensation expense (reflected in the caption “Other operation and maintenance” on the consolidated statements of income) was $6 million and $10 million for the three months ended March 31, 2006, and 2005, respectively. The income tax benefit recognized in the income statement was $3 million and $4 million for the three months ended March 31, 2006, and 2005, respectively.

The following table illustrates the effect on net income available for common stock if SCE had used the fair-value accounting method for the quarter ended March 31, 2005.


	Three Months Ended March 31,
In millions	2005
	(Unaudited)
Net income available for common stock, as reported	$	131
Add: stock-based compensation expense using the intrinsic value accounting method – net of tax		5
Less: stock-based compensation expense using the fair-value accounting method –net of tax		5
Pro forma net income available for common stock	$	131

Supplemental Accumulated Other Comprehensive Loss Information

SCE previously disclosed in Note 1 of “Notes to Consolidated Financial Statements” included in SCE’s 2005 Annual Report, that the unrealized losses on cash flow hedges relate to SCE’s interest rate swap. The swap terminated on January 5, 2001 and the related debt originally matured in 2008. This debt was redeemed in April 2006, see Note 8, “Subsequent Event.” The remaining balance of $4 million, net of tax, will no longer be reflected in accumulated other comprehensive income.

Supplemental Cash Flows Information


	Three Months Ended March 31,
In millions	2006		2005
	(Unaudited)
Cash payments for interest and taxes:
Interest – net of amounts capitalized	$	90	$	100
Tax payments		29		17

Non-cash investing and financing activities:

Details of debt exchange:
Pollution-control bonds redeemed		—	$	(49	)
Pollution-control bonds issued		—		204
Funds held in trust		—	$	155

Dividends declared but not paid	$	70	$	1

SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2. Compensation and Benefit Plans

Pension Plans

SCE previously disclosed in Note 6 of “Notes to Consolidated Financial Statements” included in SCE’s 2005 Annual Report that it expects to contribute approximately $51 million to its pension plan in 2006. As of March 31, 2006, $31 million in contributions have been made. SCE anticipates that its original expectation will be met by year-end 2006.

Expense components are:


	Three Months Ended March 31,
In millions	2006			2005
	(Unaudited)
Service cost	$	25		$	24
Interest cost		42			40
Expected return on plan assets		(56	)		(54	)
Net amortization and deferral		5			6
Expense under accounting standards		16			16
Regulatory adjustment – deferred		(2	)		(2	)
Total expense recognized	$	14		$	14

Postretirement Benefits Other Than Pensions

SCE previously disclosed in Note 6 of “Notes to Consolidated Financial Statements” included in SCE’s 2005 Annual Report that it expects to contribute approximately $77 million to its postretirement benefits other than pensions plans in 2006. As of March 31, 2006, $6 million in contributions have been made. SCE anticipates that its original expectation will be met by year-end 2006.

Expense components are:


	Three Months Ended March 31,
In millions	2006			2005
	(Unaudited)
Service cost	$	12		$	11
Interest cost		31			30
Expected return on plan assets		(27	)		(25	)
Amortization of unrecognized prior service costs		(7	)		(7	)
Amortization of unrecognized loss		11			12
Total expense	$	20		$	21

Stock-Based Compensation

Stock Options

Under various plans, SCE may grant stock options at exercise prices equal to the average of the high and low price at the grant date and other awards related to or with a value derived from Edison International common

SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of four years of continuous service, with expense recognized evenly over the vesting period, except for awards granted to retirement-eligible participants, as discussed in “Stock-Based Compensation” in Note 1. Stock-based compensation expense associated with stock options was $5 million for the three months ended March 31, 2006. Under prior accounting rules, there was no comparable expense recognized for the same period in 2005. See “Stock-Based Compensation” in Note 1 for further discussion.

Beginning with awards made in 2003, stock options accrue dividend equivalents for the first five years of the option term. Unless transferred to non-qualified deferral plan accounts, dividend equivalents accumulate without interest. Dividend equivalents are paid only on options that vest, including options that are unexercised. Dividend equivalents are paid in cash after the vesting date. Edison International has discretion to pay certain dividend equivalents in shares of Edison International common stock. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.

The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in the following table.


	For the Three Months Ended March 31,
	2006	2005
	(Unaudited)
Expected terms (in years)	9 to 10	9 to 10
Risk-free interest rate	4.3%	4.2% – 4.3%
Expected dividend yield	2.4%	2.9% – 3.1%
Weighted-average expected dividend yield	2.4%	3.1%
Expected volatility	16.2%	18.7% – 19.6%
Weighted-average volatility	16.2%	19.6%

The expected term of options granted is based on the actual remaining contractual term of the options. The risk-free interest rate for periods within the contractual life of the option is based on a 52-week historical average of the 10-year semi-annual coupon U.S. Treasury note. In 2006, expected volatility is based on the historical volatility of Edison International’s common stock for the recent 36 months. Prior to January 1, 2006, expected volatility was based on the median of the most recent 36 months historical volatility of peer companies because Edison International’s historical volatility was impacted by the California energy crisis.

A summary of the status of Edison International stock options granted to SCE employees is as follows:


			Weighted-Average
	Stock Options		Exercise Price		Remaining Contractual Term (Years)	Aggregate Intrinsic Value
			(Unaudited)
Outstanding at Dec. 31, 2005	8,587,248		$	23.22
Granted	1,156,482		$	44.30
Expired	—			—
Forfeited	(7,439	)	$	29.77
Exercised	(646,468	)	$	21.48
Outstanding at March 31, 2006	9,089,823		$	26.00
Vested and expected to vest at March 31, 2006	8,685,992		$	25.82	6.80	$	151,309,981
Exercisable at March 31, 2006	4,661,331		$	22.45	5.44	$	96,909,071

SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The weighted-average grant-date fair value of options granted during the quarters ended March 31, 2006 and 2005 was $14.47 and $11.67, respectively. The total intrinsic value of options exercised during the quarters ended March 31, 2006 and 2005, was $15 million and $8 million, respectively. At March 31, 2006, there was $38 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately 2 years.

Cash received from options exercised for the quarters ended March 31, 2006 and 2005, was $14 million and $16 million, respectively. The estimated tax benefit from options exercised was $6 million and $3 million for the quarters ended March 31, 2006 and 2005, respectively.

Performance Shares

A target number of contingent performance shares were awarded to executives in January 2004, January 2005 and March 2006, and vest at the end of December 2006, 2007 and 2008, respectively. Dividend equivalents associated with these performance shares accumulate without interest and will be payable in cash following the end of the performance period when the performance shares are paid, although Edison International has discretion to pay certain dividend equivalents in Edison International common stock. The vesting of Edison International’s performance shares is dependent upon a market condition and three years of continuous service subject to a prorated adjustment for employees who are terminated under certain circumstances or retire, but payment cannot be accelerated. The market condition is based on Edison International’s common stock performance relative to the performance of a specified group of companies at the end of a three-calendar-year period. The number of performance shares earned is determined based on Edison International’s ranking among these companies. Dividend equivalents will be adjusted to correlate to the actual number of performance shares paid. 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 common stock. Additionally, cash awards are substituted to the extent necessary to pay tax withholding or any government levies. The portion of performance shares settled in cash is classified as a share-based liability award. The fair value of these shares is remeasured at each reporting period and the related compensation expense is adjusted. The portion of performance shares payable in common stock is classified as a share-based equity award. Compensation expense related to these shares is based on the grant-date fair value. Performance shares expense is recognized ratably over the vesting period based on the fair values determined, except for awards granted to retirement-eligible participants, as discussed in “Stock-Based Compensation” in Note 1. Stock-based compensation expense associated with performance shares was $2 million and $6 million for the three months ended March 31, 2006 and 2005, respectively.

The performance shares’ fair value is determined using a Monte Carlo simulation valuation model. The Monte Carlo simulation valuation model requires various assumptions. Assumptions specifically related to SCE are noted in the following table.


	For the Three Months Ended March 31,
	2006	2005
	(Unaudited)
Risk-free interest rate	4.1% and 4.2%	2.7%
Expected volatility	16.2% and 17.2%	27.7%

The risk-free interest rate is based on a 52-week historical average of the three-year semi-annual coupon U.S. Treasury note and is used as proxy for the expected return for the specified group of companies. Volatility is based on the historical volatility of Edison International’s common stock for the recent 36 months. Historical volatility for each company in the specified group is obtained from data published by Bloomberg.

SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The total intrinsic value of performance shares settled during the quarters ended March 31, 2006 and 2005, was $37 million and $21 million, respectively, which included cash paid to settle the performance shares classified as liability awards of $8 million and $5 million for the three months ended March 31, 2006 and 2005, respectively. At March 31, 2006, there was $10 million (based on the March 31, 2006 fair value of performance shares classified as liability awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately 2 years.

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


			Weighted-Average
	Performance Shares		Grant-Date Fair Value
	(Unaudited)
Nonvested at, Dec. 31, 2005	146,280		$	39.08
Granted	45,839			53.24
Forfeited	(233	)		45.58
Nonvested at March 31, 2006	191,886		$	42.46

The weighted-average grant-date fair value of performance shares classified as equity awards granted during the quarter ended March 31, 2005, was $46.09.

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


	Performance Shares		Weighted-Average Fair Value
	(Unaudited)
Nonvested at, Dec. 31, 2005	146,400
Granted	45,905
Forfeited	(234	)

Nonvested at March 31, 2006	192,071		$	91.55

Note 3. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

SCE’s recorded estimated minimum liability to remediate its 24 identified sites is $81 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 $114 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 31 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to $9 million.

The California Public Utilities Commission (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 $55 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 $25 million. Recorded costs for the twelve months ended March 31, 2006 were $13 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Federal Income Taxes

Edison International received Revenue Agent Reports from the Internal Revenue Service (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. Many of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of penalties), if any, would benefit SCE as future tax deductions.

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. While Edison International intends to defend its tax return position with respect to this transaction, the tax benefits relating to the capital loss deductions will not be claimed for financial accounting and reporting purposes until and unless these tax losses are sustained.

In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 through 2002 to abate 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.

Federal Energy Regulatory Commission (FERC) Refund Proceedings

In 2000, the FERC initiated an investigation into the justness and reasonableness of rates charged by sellers of electricity in the California Power Exchange (PX) and California Independent System Operator (ISO) markets. On March 26, 2003, the FERC staff issued a report concluding that there had been pervasive gaming and market manipulation of both the electric and natural gas markets in California and on the West Coast during 2000–2001 and describing many of the techniques and effects of that market manipulation. 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. SCE is required to refund to customers 90% of any refunds actually realized by SCE net of litigation costs, except for the El Paso Natural Gas Company settlement agreement (see discussion in Note 9 of “Notes to Consolidated Financial Statements” in SCE’s 2005 Annual Report), and 10% will be retained by SCE as a shareholder incentive. A brief summary of the various settlements is below:

•

In November 2005, the FERC approved a settlement agreement among SCE, Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E) and several governmental entities, and Enron Corporation and a number of its affiliates (collectively Enron), most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In January 2006, SCE received cash settlement proceeds of $4 million and anticipates receiving approximately $5 million in additional cash proceeds assuming certain contingencies are satisfied. SCE also received an allowed, unsecured claim against one of the Enron debtors in the amount of $241 million. In February 2006, SCE received a partial distribution of $10 million of its allowed claim. In April 2006, SCE received a distribution on its allowed bankruptcy claim against one of the Enron debtors of approximately $29 million, and 196,245 shares of common stock of Portland General Electric Company with an aggregate value of approximately $5 million. The remaining amount of the allowed claim that will actually be realized will depend on events in Enron’s bankruptcy that impact the value of the relevant debtor estate.

•

In December 2005, the FERC approved a settlement agreement among SCE, PG&E, SDG&E, several governmental entities and certain other parties, and Reliant Energy, Inc. and a number of its affiliates. In January 2006, SCE received its $65 million share of the settlement proceeds. In March 2006, SCE received an additional $61 million.

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On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an energy settlement memorandum account (ESMA) for the purpose of recording the foregoing settlement proceeds from energy providers and allocating them in accordance with a settlement agreement. The resolution provides a mechanism whereby portions of the settlement proceeds recorded in the ESMA are allocated to recovery of SCE’s litigation costs and expenses in the FERC refund proceedings described above and the 10% shareholder incentive. Remaining amounts for each settlement are to be refunded to ratepayers through the energy resource recovery account mechanism. During 2005, SCE recognized $23 million in shareholder incentives related to the FERC refunds described above.

Investigations Regarding Performance Incentives Rewards

SCE is eligible under its CPUC-approved performance-base rate (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 has been conducting investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings of misconduct and misreporting as further discussed below. As a result of the reported events, the CPUC could institute its own proceedings to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer satisfaction, injury and illness reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose additional penalties on SCE. SCE cannot predict the outcome of these matters or estimate the potential amount of refunds, disallowances, and penalties that may be required.

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 to SCE under the PBR provisions for customer satisfaction. SCE recorded aggregate customer satisfaction rewards of $28 million for the years 1998, 1999 and 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. As a result of these findings, SCE accrued a $9 million charge in 2004 for the potential refunds of rewards that have been received.

SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of 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 general rate case.

The CPUC has not yet opened a formal investigation into this matter. However, it has submitted several data requests to SCE and has requested an opportunity to interview a number of SCE employees in the design

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organization. SCE has responded to these requests and the CPUC has conducted interviews of approximately 20 employees who were disciplined for misconduct and four senior managers and executives of the transmission and distribution business unit.

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 received $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 for any year before 2005, and it return to ratepayers the $20 million it has already received. Therefore, SCE accrued a $20 million charge in 2004 for the potential refund of these rewards. SCE has also proposed to withdraw the pending rewards for the 2001–2003 time frames.

SCE has taken other remedial action to address the issues identified, including revising its organizational structure and overall program for environmental, health and safety compliance and disciplining employees who committed wrongdoing. SCE submitted a report on the results of its investigation to the CPUC on December 3, 2004. As with the customer satisfaction matter, the CPUC has not yet opened a formal investigation into this matter.

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. The order reversed an arbitrator’s award that had affirmed the ISO’s characterization in May 2000 of the charges as Intra-Zonal Congestion costs and allocation of those charges to schedule coordinators in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from schedule coordinators in the affected zone to the responsible participating transmission owner, SCE. The potential cost to SCE, net of amounts SCE expects to receive through the PX, SCE’s schedule coordinators at the time, is estimated to be approximately $20 million to $25 million, including interest. On April 20, 2005, the FERC stayed its April 20, 2004 order during the pendency of SCE’s appeal filed with the Court of Appeals for the D.C. Circuit. On March 7, 2006, the Court of Appeals remanded the case back to the FERC at the FERC’s request and with SCE’s consent. A decision is expected in late 2006. The FERC may require SCE to pay these costs, but SCE does not believe this outcome is probable. If SCE is required to pay these costs, SCE may seek recovery in its reliability service rates.

Navajo Nation Litigation

In June 1999, the Navajo Nation filed a complaint in the United States District Court for the District of Columbia (D.C. District Court) against Peabody Holding Company (Peabody) and certain of its affiliates, Salt River Project

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Agricultural Improvement and Power District, and SCE arising out of the coal supply agreement for the Mohave Generating Station (Mohave). The complaint asserts claims for, among other things, violations of the federal Racketeer Influenced and Corrupt Organizations statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentation 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, as well as a declaration that Peabody’s lease and contract rights to mine coal on Navajo Nation lands should be terminated. SCE joined Peabody’s motion to strike the Navajo Nation’s complaint. In addition, SCE and other defendants filed motions to dismiss. The D.C. District Court denied these motions for dismissal, except for Salt River Project Agricultural Improvement and Power District’s motion for its separate dismissal from the lawsuit.

Certain issues related to this case were addressed by the United States Supreme Court in a separate legal proceeding filed by the Navajo Nation in the United States Court of Federal Claims against the United States Department of Interior. In that action, the Navajo Nation claimed that the Government breached its fiduciary duty concerning negotiations relating to the coal lease involved in the Navajo Nation’s lawsuit against SCE and Peabody. On March 4, 2003, the Supreme Court concluded, by majority decision, that there was no breach of a fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. Based on the Supreme Court’s conclusion, SCE and Peabody brought motions to dismiss or for summary judgment in the D.C. District Court action but the D.C. District Court denied the motions on April 13, 2004.

The Court of Appeals for the Federal Circuit, acting on a suggestion filed by the Navajo Nation on remand from the Supreme Court’s March 4, 2003 decision held, in an October 24, 2003 decision that the Supreme Court’s decision was focused on three specific statutes or regulations and therefore did not address the question of whether a network of other statutes, treaties and regulations imposed judicially enforceable fiduciary duties on the United States during the time period in question. On March 16, 2004, the Federal Circuit issued an order remanding the case against the Government to the Court of Federal Claims, which considered (1) whether the Navajo Nation previously waived its “network of other laws” argument and, (2) if not, whether the Navajo Nation can establish that the Government breached any fiduciary duties pursuant to such “network.” On December 20, 2005, the Court of Federal Claims issued its ruling and found that although there was no waiver, the Navajo Nation did not establish that a “network of other laws” created a judicially enforceable trust obligation. The Navajo Nation filed a notice of appeal from this ruling on February 14, 2006.

Pursuant to a joint request of the parties, the D.C. District Court granted a stay of the action in that court to allow the parties to attempt to resolve, through facilitated negotiations, all issues associated with Mohave. Negotiations are ongoing and the stay has been continued until further order of the court.

SCE cannot predict the outcome of the 1999 Navajo Nation’s complaint against SCE, the impact on the complaint of the Supreme Court’s decision and the recent Court of Federal Claims ruling in the Navajo Nation’s suit against the Government, or the impact of the complaint on the possibility of resumed operation of Mohave following the cessation of operation on December 31, 2005.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $10.8 billion. SCE and other owners of San Onofre Nuclear Generating Station (San Onofre) and Palo Verde Nuclear Generating Station (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

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insurance at that plant site. Federal regulations require this secondary level of financial protection. The Nuclear Regulatory Commission 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 on August 31, 2008. Based on its ownership interests, SCE could be required to pay a maximum of $199 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 $42 million per year. Insurance premiums are charged to operating expense.

Procurement of Renewable Resources

California law requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2017. The Joint Energy Action Plan adopted in 2003 by the CPUC and the California Energy Commission (CEC) accelerated the deadline to 2010.

SCE entered into a contract with Calpine Energy Services, L.P. (Calpine) to purchase the output of certain existing geothermal facilities in northern California. On January 30, 2003, the CPUC issued a resolution approving the contract. SCE interpreted the resolution as authorizing SCE to count all of the output of the geothermal facilities towards the obligation to increase SCE’s procurement from renewable resources and counted the entire output of the facilities toward its 1% obligation in 2003, 2004 and 2005. On July 21, 2005, the CPUC issued a decision stating that SCE can only count procurement pursuant to the Calpine contract towards its 1% annual renewable procurement requirement if it is certified as “incremental” by the CEC. On February 1, 2006, the CEC certified approximately 25% and 17% of SCE’s 2003 and 2004 procurement, respectively, from the Calpine geothermal facilities as “incremental.” A similar outcome is anticipated with respect to the CEC’s certification review for 2005.

On August 26, 2005, SCE filed an application for rehearing and a petition for modification of the CPUC’s July 21, 2005 decision. On January 26, 2006, the CPUC denied SCE’s application for rehearing of the decision. The CPUC has not yet ruled on SCE’s petition for modification. The petition for modification seeks a clarification that SCE will not be subjected to penalties for relying on the CPUC’s 2003 resolution in submitting compliance reports to the CPUC and planning its subsequent renewable procurement activities. The petition for modification also seeks an express finding that the decision will be applied prospectively only; i.e., that no past procurement deficits will accrue for any prior period based on the decision.

If SCE is not successful in its attempt to modify the July 21, 2005 CPUC decision and can only count the output deemed “incremental” by the CEC, SCE could have deficits in meeting its renewable procurement obligations for

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2003 and 2004. However, based on the CPUC’s rules for compliance with renewable procurement targets, SCE may have until 2007 to make up these deficits before becoming subject to penalties for those years. The CEC’s and the CPUC’s treatment of the output from the geothermal facilities could also result in SCE being deemed to be out of compliance in 2005 and 2006. Under current CPUC decisions, potential penalties for SCE’s failure to achieve its renewable procurement obligations for any year will be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance filing.

On December 20, 2005, Calpine and certain of its affiliates initiated Chapter 11 bankruptcy proceedings in the United States Bankruptcy Court for the Southern District of New York. As part of those proceedings, Calpine sought to reject its contract with SCE as of the petition filing date. On January 27, 2006, after the matter had been withdrawn from the Bankruptcy Court’s jurisdiction, the United States District Court for the Southern District of New York denied Calpine’s motion to reject the contract and ruled that the FERC has exclusive jurisdiction to alter the terms of the contract with SCE. Calpine has appealed the District Court’s ruling to the United States Court of Appeals for the Second Circuit. Calpine may also file a petition with the FERC seeking authorization to reject the contract. The CPUC may take the position that any authorized rejection of the contract would cause SCE to be out of compliance with its renewable procurement obligations during any period in which renewable electricity deliveries are reduced or eliminated as a result of the rejection.

Further, in December 2005, SCE made filings advising the CPUC that the need for transmission upgrades to interconnect new renewable projects and the time it will take under the current process to license and construct such transmission upgrades may prevent SCE from meeting its statutory renewables procurement obligations through 2010 and potentially beyond 2010 depending in part on the results of a pending solicitation for new renewable resources. SCE has requested that the CPUC take several actions in order to expedite the licensing process for transmission upgrades. The CPUC may take the position that SCE’s failure to meet the 20% goal by 2010 due to transmission constraints would cause SCE to be out of compliance with its renewable procurement obligations.

Under the CPUC’s current rules, the maximum penalty for failing to achieve renewables procurement targets is $25 million per year. SCE cannot predict whether it will be assessed penalties.

Schedule Coordinator Tariff Dispute

SCE serves as a schedule coordinator for the Los Angeles Department of Water & Power (DWP) over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund for FERC-authorized charges incurred by SCE on the DWP’s behalf. The schedule 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 the FERC declare that SCE was obligated to serve as the DWP’s schedule 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 at the FERC. As a result, SCE could be required to refund all or part of the amounts collected from the DWP under the tariff. During the fourth quarter of 2005, SCE accrued a $25 million charge to earnings for the potential refunds. If the FERC ultimately rules that SCE may not collect the schedule coordinator charges from the DWP and requires the amounts collected to be refunded to the DWP, SCE would attempt to recover the schedule coordinator charges from all transmission grid customers through another regulatory mechanism. However, the availability of other recovery mechanisms is uncertain, and ultimate recovery of the schedule coordinator charges cannot be assured.

Spent Nuclear Fuel

Under federal law, the United States Department of Energy (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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DOE did not meet its obligation to begin acceptance of spent nuclear fuel not later than 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, when SCE and the DOE filed a Joint Status Report in which SCE sought to lift the stay and the government opposed lifting the stay. On April 19, 2006, the Court ordered SCE and the DOE to file another Joint Status Report, by May 8, 2006, outlining the specific issues in the case and discussing whether any cases currently pending before the Court of Claims or Federal Circuit Court of Appeals are expected to address issues in SCE’s case. SCE will continue to pursue having the stay lifted as soon as possible.

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 is now sufficient space in the Unit 2 and 3 spent fuel pools to meet plant requirements through mid-2007 and mid-2008, respectively. In order to maintain a full core off-load capability, SCE is planning to begin moving Unit 2 and 3 spent fuel into the independent spent fuel storage installation by early 2007.

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

Note 4. Commitments

The following is an update to SCE’s commitments. See Note 8 of “Notes to Consolidated Financial Statements” included in SCE’s 2005 Annual Report for a detailed discussion.

Fuel Supply Commitments

During the first quarter of 2006, the nuclear fuel commitments increased due to the additional costs associated with uranium enrichment and fuel fabrication services. SCE’s additional nuclear fuel commitments are currently estimated to be: 2006 – $9 million; 2007 – $6 million; 2008 – $4 million; 2009 – $8 million; and 2010 – $2 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. The generating station has not operated since 2001. 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,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Note 5. Business Segments

SCE’s reportable business segments include the rate-regulated electric utility segment and the variable interest entities (VIEs) segment. The VIEs were consolidated as of March 31, 2004. Additional details on the VIE segment are in Note 1 of “Notes to Consolidated Financial Statements” included in SCE’s 2005 Annual Report. 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 March 31, 2006:
Cash and equivalents	$	62	$	80	$	—		$	142
Accounts receivable–net		631		130		(88	)		673
Inventory		210		20		—			230
Other current assets		72		2		—			74
Nonutility property–net of depreciation		737		337		—			1,074
Other long-term assets		490		8		—			498
Total assets		24,354		577		(88	)		24,843
Accounts payable		635		140		(88	)		687
Accrued interest		95		1		—			96
Other current liabilities		681		2		—			683
Long-term debt		5,053		54		—			5,107
Asset retirement obligations		2,628		13		—			2,641
Minority interest		—		367		—			367
Total liabilities and shareholder’s equity		24,354		577		(88	)		24,843

Balance Sheet Items as of December 31, 2005:
Cash and equivalents	$	23	$	120	$	—		$	143
Accounts receivable–net		794		174		(119	)		849
Inventory		202		18		—			220
Other current assets		88		4		—			92
Nonutility property–net of depreciation		741		345		—			1,086
Other long-term assets		493		10		—			503
Total assets		24,151		671		(119	)		24,703
Accounts payable		813		204		(119	)		898
Other current liabilities		721		2		—			723
Long-term debt		4,615		54		—			4,669
Asset retirement obligations		2,608		13		—			2,621
Minority interest		—		398		—			398
Total liabilities and shareholder’s equity		24,151		671		(119	)		24,703

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In millions	Electric Utility		VIEs		Eliminations*			SCE
	(Unaudited)
Income Statement Items for the Three Months Ended March 31, 2006:
Operating revenue	$	2,100		$309	$	(192	)	$	2,217
Fuel		86		225		—			311
Purchased power		1,205		—		(192	)		1,013
Other operation and maintenance		592		25		—			617
Depreciation, decommissioning and amortization		244		9		—			253
Total operating expenses		1,818		259		(192	)		1,885
Operating income		282		50		—			332
Minority interest		—		50		—			50
Net income		133		—		—			133

	(Unaudited)
Income Statement Items for the Three Months Ended March 31, 2005:
Operating revenue	$	1,807	$	274	$	(173	)	$	1,908
Fuel		62		193		—			255
Purchased power		561		—		(173	)		388
Other operation and maintenance		577		24		—			601
Depreciation, decommissioning and amortization		213		9		—			222
Total operating expenses		1,527		226		(173	)		1,580
Operating income		280		48		—			328
Minority interest		—		48		—			48
Net income		132		—		—			132

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

Note 6. Liabilities and Lines of Credit

Short-term debt is used to finance fuel inventories, balancing account undercollections and general, temporary cash requirements. At March 31, 2006, the outstanding short-term debt and weighted-average interest rate was $188 million at 4.79%.

Note 7. Preferred and Preference Stock Not Subject to Mandatory Redemption

In January 2006, SCE issued two million shares of 6.0% Series C preference stock (non-cumulative, $100 liquidation value) and received net proceeds of $197 million. The Series C preference stock may not be redeemed prior to January 31, 2011. After January 31, 2011, SCE may, at its option, redeem the shares in whole or in part. The Series C preference stock has the same general characteristics as the Series A and B preference stock. Additional details on preference stock are in Note 4 of “Notes to Consolidated Financial Statements” included in SCE’s 2005 Annual Report.

Note 8. Subsequent Events

In April 2006, SCE issued $331 million of pollution-control bonds. The issuance included $196 million of 4.10% bonds due in April 2013 and $135 million of 4.25% bonds due in November 2016. The proceeds from the issuance of the bonds were used to call and redeem $135 million of pollution-control bonds due March 2008 and $196 million of pollution-control bonds due February 2008.

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 (MD&A) for the three-month period ended March 31, 2006 discusses material changes in the financial condition, results of operations and other developments of Southern California Edison Company (SCE) since December 31, 2005, and as compared to the three-month period ended March 31, 2005. This discussion presumes that the reader has read or has access to SCE’s MD&A for the calendar year 2005 (the year-ended 2005 MD&A), which was included in SCE’s 2005 annual report to shareholders and incorporated by reference into SCE’s Annual Report on Form 10-K for the year ended December 31, 2005, 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, 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 California Public Utilities Commission (CPUC) 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 and 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 and output;

•

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;

•

general political, economic and business conditions;

•

weather conditions, natural disasters and other unforeseen events; and

•

changes in the fair value of investments and other assets.

Additional information about risks and uncertainties, including more detail about the factors described above, are discussed throughout this MD&A and the “Risk Factors” section included in Part I, Item 1A of SCE’s annual report on Form 10-K for the year ended 2005. Readers are urged to read this entire report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect SCE’s business. Forward-looking statements speak only as of the date they are made and SCE is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by SCE with the Securities and Exchange Commission.

This MD&A 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 the Federal Energy Regulatory Commission (FERC).

This MD&A is presented in eight major sections. The MD&A begins with a discussion of current developments. The remaining sections of the MD&A include: liquidity; regulatory matters; other developments; market risk exposures; results of operations and historical cash flow analysis; new accounting pronouncements; and commitments, guarantees and indemnities.

CURRENT DEVELOPMENTS

2006 General Rate Case Proceeding

On December 21, 2004, SCE filed its application for a 2006 General Rate Case (GRC) and subsequently revised its requested 2006 base rate revenue requirement to $3.96 billion, an increase of $325 million over SCE’s 2005 base rate revenue requirement. SCE also proposed revised base rate revenue increases of $108 million for 2007 and $113 million for 2008.

On April 13, 2006, the CPUC assigned administrative law judge revised his January 17, 2006 proposed decision to correct several technical and substantive errors. On May 5, 2006, a third proposed decision was issued to increase authorized operating and maintenance expenses by an additional $45 million over the earlier revised proposed decision. The latest proposed decision would result in a 2006 base rate revenue requirement of $3.78 billion, an increase of $133 million over SCE’s 2005 base rate revenue requirement, and further increases of $74 million in 2007 and $104 million in 2008. A final CPUC decision is expected in the second quarter of 2006. See “Regulatory Matters—Current Regulatory Developments—2006 General Rate Case Proceeding.”

LIQUIDITY

Overview

As of March 31, 2006, SCE had cash and equivalents of $142 million ($80 million of which was held by SCE’s consolidated Variable Interest Entities). As of March 31, 2006, long-term debt, including current maturities of long-term debt, was $5.4 billion. In December 2005, SCE replaced its $1.25 billion credit facility with a $1.7 billion five-year senior secured credit facility. The security pledged (first and refunding mortgage bonds) for the new facility can be removed at SCE’s discretion. If SCE chooses to remove the security, the credit facility’s pricing will change to an unsecured basis per the terms of the credit facility agreement. As of March 31, 2006, SCE’s credit facility supported $269 million in letters of credit and $188 million of commercial paper outstanding, leaving $1.2 billion available under the credit facility.

SCE’s estimated cash outflows during the twelve-month period following March 31, 2006 consist of:

•

Debt maturities of approximately $246 million of rate reduction notes that have a separate nonbypassable recovery mechanism approved by state legislation and CPUC decisions;

•

Projected capital expenditures primarily to replace and expand distribution and transmission infrastructure and construct generation assets, as discussed below;

•

Dividend payments to SCE’s parent company. On March 1, 2006, the Board of Directors of SCE declared a $60 million dividend to Edison International which was paid on April 28, 2006. On April 27, 2006, the Board of Directors of SCE declared an additional $60 million dividend payable to Edison International;

•

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.

In April 2006, SCE issued $331 million of pollution-control bonds. The issuance included $196 million of 4.10% bonds due in April 2013 and $135 million of 4.25% bonds due in November 2016. The proceeds from the issuance of the bonds were used to call and redeem $196 million of pollution-control bonds due February 2008 and $135 million of pollution-control bonds due March 2008.

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

Credit Ratings

At March 31, 2006, SCE’s credit rating on long-term senior secured debt from Standard & Poor’s Rating Services and Moody’s Investors Service were BBB+ and A3, respectively. At March 31, 2005, SCE’s short-term (commercial paper) credit ratings from Standard & Poor’s and Moody’s were A-2 and P-2, respectively.

Dividend Restrictions and Debt Covenants

The CPUC regulates SCE’s capital structure and limits the dividends it may pay Edison International. In SCE’s most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE determines compliance with this capital structure based on a 13-month weighted-average calculation. At March 31, 2006, SCE’s 13-month weighted-average common equity component of total capitalization was 50%. At March 31, 2006, SCE had the capacity to pay $157 million in additional dividends based on the 13-month weighted-average method. Based on recorded March 31, 2006 balances, SCE’s common equity to total capitalization ratio, for rate-making purposes, was 49%. SCE had the capacity to pay $62 million of additional dividends to Edison International based on March 31, 2006 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 March 31, 2006, SCE’s debt to total capitalization ratio was 0.46 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 and changes in market prices relative to contractual commitments, and other factors. At March 31, 2006, SCE had a net deposit of $189 million (comprised of $87 million in cash and reflected in “Margin and collateral deposits” on the balance sheet and $102 million in letters of credit) with a broker. In addition, SCE has deposited $187 million (comprised of $21 million in cash and reflected in “Margin and collateral deposits” on the balance sheet and $167 million in letters of credit) with other brokers and counterparties. Cash deposits with brokers and counterparties earn interest at various rates.

Margin and collateral deposits in support of power contracts and trading activities fluctuate with changes in market prices. Future margin and collateral requirements may be higher or lower than the margin collateral requirements as of March 31, 2006, based on future market prices and volumes of contractual and trading activity.

REGULATORY MATTERS

Current Regulatory Developments

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

2006 General Rate Case Proceeding

SCE’s 2006 GRC application requested a revised 2006 base rate revenue requirement of $3.96 billion, an increase of $325 million over SCE’s 2005 base rate revenue. The requested increase is primarily driven by capital expenditures needed to accommodate infrastructure replacement and customer and load growth, and higher operating and maintenance expenses, particularly in SCE’s transmission and distribution business unit. SCE also requested the CPUC continue SCE’s existing post-test year rate-making mechanism, which would result in further revised base rate revenue increases of $108 million in 2007 and $113 million in 2008.

On April 13, 2006, the CPUC assigned administrative law judge revised his January 17, 2006 proposed decision to correct several technical and substantive errors. On May 5, 2006, a third proposed decision was issued to increase authorized operating and maintenance expenses by an additional $45 million over the earlier revised proposed decision. The latest proposed decision would result in a 2006 base rate revenue requirement of $3.78 billion, an increase of $133 million over SCE’s 2005 base rate revenue, and further increases of $74 million in 2007 and $104 million in 2008. A final CPUC decision is expected in the second quarter of 2006. SCE cannot predict the final outcome of SCE’s GRC application.

2007 Cost of Capital Proceeding

On March 27, 2006, SCE initiated proceedings requesting the CPUC to waive the requirement that SCE file a 2007 cost of capital application and instead file its next such application in 2007 for year 2008. If SCE’s waiver application is granted, SCE’s authorized capital structure, return on common equity of 11.6% and overall rate of return on capital of 8.77% will not change for 2007. SCE anticipates a CPUC decision on its waiver application by the fourth quarter of 2006.

Energy Resource Recovery Account Proceedings

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings” in the year-ended 2005 MD&A, the Energy Resource Recovery Account (ERRA) is the balancing account mechanism to track and recover SCE’s fuel and procurement-related costs. If the ERRA balancing account incurs an overcollection or undercollection in excess of 4% of SCE’s prior year’s generation revenue, the CPUC has established a “trigger” mechanism, whereby SCE must file an application in which it can request an emergency rate adjustment if the ERRA overcollection or undercollection exceeds 5% of SCE’s prior year’s generation revenue. In February 2006, the ERRA was undercollected by $206 million, which was 5.16% of SCE’s prior year’s generation revenue. On April 14, 2006 SCE filed an ERRA trigger application. In its application, SCE forecasts that the ERRA undercollection will be eliminated by the end of June 2006 as a result of the implementation of the CPUC’s January 2005 ERRA decision (see “Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings—ERRA Forecast” in the year-ended 2005 MD&A for further discussion) and no further rate action by the CPUC would be necessary. A CPUC decision on this application is expected in June 2006. As of March 31, 2006, the ERRA was undercollected by $130 million, which was 3.27% of SCE’s prior year’s generation revenue.

Procurement of Renewable Resources

On August 26, 2005, SCE filed an application for rehearing and a petition for modification of the CPUC’s July 21, 2005 decision. On January 26, 2006, the CPUC denied SCE’s application for rehearing of the decision. On April 20, 2006, the CPUC issued a draft decision denying SCE’s petition for modification. A decision is expected in the second quarter of 2006.

If SCE can only count the output deemed “incremental” by the CEC, SCE could have deficits in meeting its renewable procurement obligations for 2003 and 2004. However, based on the CPUC’s rules for compliance with renewable procurement targets, SCE may have until 2007 to make up these deficits before becoming subject to penalties for those years. The CEC’s and the CPUC’s treatment of the output from the geothermal facilities could also result in SCE being deemed to be out of compliance in 2005 and 2006. Under current CPUC decisions, potential penalties for SCE’s failure to achieve its renewable procurement obligations for any year will 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 renewables procurement targets is $25 million per year. SCE cannot predict whether it will be assessed penalties.

Mohave Generating Station and Related Proceedings

Mohave Generating Station (Mohave) obtained all of its coal supply from the Black Mesa Mine in northeast Arizona, located on lands of the Navajo Nation and Hopi Tribe (the Tribes). This coal was delivered from the mine to Mohave by means of a coal slurry pipeline, which requires water from wells located on lands belonging to the Tribes in the mine vicinity. Uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave co-owners from making approximately $1.1 billion in Mohave-related investments (SCE’s share is $605 million), including the installation of enhanced pollution-control equipment required by a 1999 air-quality consent decree in order for Mohave to operate beyond 2005. Accordingly, the plant ceased operations, as scheduled, on December 31, 2005, consistent with the provisions of the consent decree.

SCE continues to pursue all reasonable options to return Mohave to service in compliance with the consent decree. Negotiations, water studies, and other efforts among SCE and the other relevant parties continue in an attempt to resolve Mohave’s coal and water supply issues. Although progress has been made with respect to certain issues, no complete resolution has been reached to date. Assuming substantial resolution of the coal and water issues in 2006, and CPUC authorization of the necessary investments, SCE estimates that Mohave could return to service in approximately 2010. However, at this time, SCE does not know the length of the suspension period, and a permanent suspension remains possible. During the suspension period the absence of Mohave as an available resource will impact SCE’s resource requirements and resource planning.

San Onofre Nuclear Generating Station Steam Generators

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—San Onofre Nuclear Generating Station Steam Generators” in the year-ended 2005 MD&A, on December 15, 2005, the CPUC issued a final decision on SCE’s application for replacement of SCE’s San Onofre Units 2 and 3 steam generators. SCE provided its acceptance of the decision to the CPUC on March 6, 2006.

The city of Anaheim opted out of the project and agreed to transfer its 3.16% share of San Onofre to SCE. In March 2006, SCE filed applications to the Nuclear Regulatory Commission (NRC) and the FERC requesting authority to transfer Anaheim’s share to SCE. Also, in March 2006, SCE filed an application with the CPUC requesting rate recovery for Anaheim’s share of San Onofre operating and decommissioning costs. In April 2006, the FERC granted SCE authority to transfer Anaheim’s share to SCE. The transfer of Anaheim’s share is contingent upon receipt of regulatory approvals.

On April 13, 2006, SCE and San Diego Gas & Electric Company (SDG&E) settled a dispute regarding SDG&E’s decision to opt out of steam generator replacement. As a result, on April 14, 2006, SDG&E applied to the CPUC to participate in the steam generator replacement and retain its 20% share of San Onofre contingent upon CPUC adoption of its application subject to certain conditions including, operating and maintenance expense balancing account and an 11.6% return on equity for SDG&E’s San Onofre capital investment. If the CPUC’s decision is not acceptable to SDG&E, it may file an application with the CPUC to opt out of steam generator replacement and have its ownership share of San Onofre reduced.

FERC Refund Proceedings

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—FERC Refund Proceedings” in the year-ended 2005 MD&A, 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. In November 2005, SCE and other parties entered into a settlement agreement with Enron Corporation and a number of its affiliates (collectively Enron), most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In April 2006, SCE received a distribution on its allowed bankruptcy claim against one of the Enron debtors of approximately $29 million, and 196,245 shares of common stock of Portland General Electric Company with an aggregate value of approximately $5 million. In December 2005, the FERC approved a settlement agreement among SCE, Pacific Gas and Electric Company, SDG&E, several governmental entities and certain other parties, and Reliant Energy, Inc. and a number of its affiliates. In January 2006, SCE received its $65 million share of the settlement proceeds. In March 2006, SCE received an additional $61 million. 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.

OTHER DEVELOPMENTS

Environmental Matters

SCE’s power plants, in particular its coal-fired plants, may be affected by recent developments in federal and state laws and regulations. These laws and regulations, including those relating to sulfur dioxide and nitrogen oxide emissions, mercury emissions, ozone and fine particulate matter emissions, regional haze, and climate change, may require SCE to make significant capital expenditures at its facilities. The developments in certain of these laws and regulations are discussed in more detail below. These developments will continue to be monitored by SCE 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 2005 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:

Environmental Remediation

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 $55 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

Palo Verde Nuclear Generating Station

Between December 2005 when Palo Verde Unit 1 returned to service from its refueling and steam generator replacement outage and March 21, 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 21, 2006, Arizona Public Service, the Operating Agent for Palo Verde Unit 1 decided to remove the unit from service completely until the vibration problem could be resolved. SCE expects that the outage will continue into late June. Incremental replacement power costs are expected to be recovered through the ERRA ratemaking mechanism.

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. See “Market Risk Exposures” in the year-ended 2005 MD&A for a complete discussion of SCE’s market risk exposures.

Commodity Price Risk

The following table summarizes the net fair values for outstanding physical and financial derivative investments used at SCE to mitigate its exposures to commodity price risk:


		March 31, 2006				December 31, 2005
In millions	Assets		Liabilities		Assets		Liabilities
Energy options and tolling arrangements	$	—	$	20	$	25	$	—
Forward physicals (power)		—		105		—		49
Gas options, swaps, and forward arrangements		—		110		105		—
Total	$	—	$	235	$	130	$	49

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 first quarter 2006 net income available for common stock was $121 million, compared with $131 million in first quarter 2005. The decrease is primarily due to the impact of higher operating costs associated with the utility’s customer and system growth and the delay in receiving the 2006 GRC decision. When the 2006 GRC decision is issued, SCE will be authorized by the CPUC to recover its revenue requirement retroactive to January 12, 2006. The decrease in SCE’s earnings was partially offset by the return on investment earned by SCE’s newly constructed Mountainview plant.

Operating Revenue

SCE’s retail sales represented approximately 85% and 80% of operating revenue for the first quarter of 2006 and 2005, respectively. Due to warmer weather during the summer months, operating revenue during the third quarter of each year is generally significantly higher than other quarters.

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


In millions Three-Month Period Ended March 31,	2006 vs. 2005
Operating revenue
Rate changes (including unbilled)	$	156
Sales volume changes (including unbilled)		20
Deferred revenue		185
Sales for resale		(89	)
SCE’s variable interest entities		16
Other (including intercompany transactions)		21
Total	$	309

Total operating revenue increased by $309 million in 2006 (as shown in the table above). The increase resulting from rate changes was due to the rate change implemented on February 4, 2006 arising from SCE’s 2006 ERRA decision (see “Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings—ERRA Forecast” in the year-ended 2005 MD&A for further discussion). The increase in operating revenue resulting from sales volume changes was mainly due to an increase in kilowatt-hours (kWh) sold, including SCE providing a greater amount of energy to its customers from its own sources in 2006, compared to 2005. The change in deferred revenue reflects the recognition of approximately $107 million of revenue in 2006, resulting from balancing account undercollections, compared to the deferral of approximately $78 million of revenue in 2005. Operating revenue from sales for resale represents the sale of excess energy. Excess energy from SCE sources may exist at certain times, which then is resold in the energy markets. Sales for resale revenue decreased due to a lesser amount of excess energy in the first quarter of 2006, as compared to the same period in 2005. Revenue from sales for resale is refunded to customers through the ERRA rate-making mechanism and does not impact earnings. SCE’s variable interest entities revenue represents the recognition of revenue resulting from the consolidation of SCE’s variable interest entities.

Amounts SCE bills and collects from its customers for electric power purchased and sold by the California Department of Water Resources (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 $568 million and $510 million for the three-month periods ended March 31, 2006 and 2005, respectively.

Operating Expenses

Fuel Expense

SCE’s fuel expense increased $56 million for the three-month period ended March 31, 2006. The 2006 increase was primarily due to $55 million of fuel expense in the first quarter of 2006 resulting from SCE’s newly constructed Mountainview project which became operational in December 2005, and increased fuel expense related to SCE’s consolidated variable interest entities. Fuel expense related to SCE’s consolidated variable interest entities was $225 million and $193 million for the three-month periods ended March 31, 2006 and 2005, respectively. The increase in fuel expense was partially offset by a decrease in fuel expense of approximately $15 million at SCE’s Mohave Generating Station resulting from the electric generation operations being ceased on December 31, 2005 (see “Regulatory Matters—Mohave Generating Station and Related Proceedings” for further discussion), lower nuclear fuel expense of approximately $5 million resulting from a planned refueling and maintenance outage at SCE’s San Onofre Unit 2 and a Department of Energy settlement refund of approximately $10 million related to crude oil overcharges. The settlement refund is returned to ratepayers through the ERRA mechanism.

Purchased-Power Expense

Purchased-power expense increased $625 million for the three-month period ended March 31, 2006. The 2006 increase was mainly due to net realized and unrealized losses on economic hedging transactions and higher

firm energy and qualifying facilities (QF)-related purchases. Net realized and unrealized losses related to economic hedging transactions increased purchased-power expense by approximately $410 million in 2006, as compared to net realized and unrealized gains of approximately $150 million which decreased purchased-power expense in 2005. Firm energy purchases increased by approximately $30 million primarily resulting from an increase in prices in 2006, as compared to 2005, and QF-related purchases increased by approximately $50 million in 2006, as compared to 2005 (as discussed below). The consolidation of SCE’s variable interest entities resulted in a $190 million and a $175 million reduction in purchased-power expense for the three-month periods ended March 31, 2006 and 2005, respectively.

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. Effective May 2002, energy payments for most renewable QFs were converted to a fixed price of 5.37¢-per-kWh until April 2007. Average spot natural gas prices were higher during 2006 as compared to 2005. The higher expenses related to power purchased from QFs were mainly due to higher average spot natural gas prices, partially offset by lower kWh purchases.

Provisions for Regulatory Adjustment Clauses – Net

Provisions for regulatory adjustment clauses – net decreased $428 million for the three-month period ended March 31, 2006. The 2006 decrease was mainly due to higher net unrealized losses of approximately $490 million related to economic hedging transactions (mentioned above in purchased-power expense) that, if realized, would be recovered from ratepayers, partially offset by lower net undercollections of purchased-power, fuel, and operation and maintenance expenses of approximately $50 million resulting from rate increases implemented in April 2005 and February 2006, and the recognition of previously deferred revenue.

Other Operation and Maintenance Expense

SCE’s other operation and maintenance expense increased $16 million in the first quarter of 2006, as compared to the first quarter in 2005. The 2006 increase was mainly due to higher generation-related costs of approximately $30 million primarily resulting from the planned refueling and maintenance outage at SCE’s San Onofre Unit 2 and an increase in demand-side management costs of approximately $10 million, partially offset by a decrease in reliability costs of approximately $30 million resulting from a decrease in must-run units. Demand-side management and reliability costs are recovered through regulatory mechanisms approved by the CPUC and the FERC, respectively.

Depreciation, Decommissioning and Amortization Expense

SCE’s depreciation, decommissioning and amortization expense increased $31 million in the first quarter of 2006. The increase in 2006 is mainly due to an increase in depreciation expense resulting from additions to transmission and distribution assets, and higher investment earnings from SCE’s nuclear decommissioning trusts. The earnings are also recorded in operating revenue. As a result, nuclear decommissioning trust earnings have no impact on net income.

Other Income and Deductions

Interest and Dividend Income

SCE’s interest and dividend income increased $6 million in the first quarter of 2006, as compared to the first quarter of 2005. The 2006 increase was mainly due to higher interest income resulting from higher balancing account undercollections and higher short-term interest rates in 2006 as compared to 2005.

Other Nonoperating Income

SCE’s other nonoperating income increased in the first quarter of 2006, as compared to the first quarter of 2005, mainly due to an increase in incentive rewards related to the efficient operation of Palo Verde and

corporate-owned life insurance proceeds. The incentive rewards approved by the CPUC for the efficient operation of Palo Verde were $13 million in the first quarter of 2006 and $10 million in the first quarter of 2005.

Income Tax

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

Net cash provided by operating activities was $320 million in 2006 and $428 million in 2005. The 2006 change in cash provided by operating activities from continuing operations was mainly due to a change in working capital items resulting from the timing of cash receipts and disbursements.

Cash Flows from Financing Activities

SCE’s short term debt is normally used for working capital requirements. Long-term debt is used mainly to finance the utility’s rate base. External financings are influenced by market conditions and other factors.

Financing activities in the first quarter of 2006 included activities related to the rebalancing of SCE’s capital structure and rate base growth. SCE’s first quarter 2006 financing activity included the issuance of $500 million of first and refunding mortgage bonds. The issuance included $350 million of 5.625% bonds due in 2036 and $150 million of floating rate bonds due in 2009. The proceeds were used 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 addition, in January 2006, SCE issued two million shares of 6% Series C preference stock (non-cumulative, $100 liquidation value) and received net proceeds of $197 million. Financing activities in 2006 also include dividend payments of $81 million paid to Edison International.

Financing activities in the first quarter of 2005 included activities related to the rebalancing of SCE’s capital structure. SCE’s first quarter 2005 financing activity included the issuance of $650 million of first and refunding mortgage bonds. The issuance included $400 million of 5% bonds due in 2016 and $250 million of 5.55% bonds due in 2036. The proceeds were used to redeem the remaining $50,000 of its 8% first and refunding mortgage bonds due February 2007 (Series 2003A) and $650 million of the $966 million 8% first and refunding mortgage bonds due February 2007 (Series 2003B).

Cash Flows from Investing Activities

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

Investing activities in the first quarter of 2006 reflect $494 million in capital expenditures, primarily for transmission and distribution assets, including approximately $17 million for nuclear fuel acquisitions and approximately $4 million related to the Mountainview project.

Investing activities in the first quarter of 2005 reflect $364 million in capital expenditures, primarily for transmission and distribution assets, including approximately $14 million for nuclear fuel acquisitions and approximately $50 million related to the Mountainview project.

NEW ACCOUNTING PRONOUNCEMENTS

COMMITMENTS, GUARANTEES AND INDEMNITIES

The following is an update to SCE’s commitments, guarantees and indemnities. See the section, “Commitments, Guarantees and Indemnities,” in the year-ended 2005 MD&A for a detailed discussion.

Fuel Supply Commitments

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 6. Exhibits


3.1		Certificate of Restated Articles of Incorporation of Southern California Edison Company, effective March 2, 2006 (File No. 1-2313, filed as Exhibit 3.1 to Southern California Edison Company’s Form 10-K for the year ended December 31, 2005)*

10.1		Letter agreement between Robert G. Foster and Southern California Edison Company, dated April 25, 2006 (File No. 1-9936, filed as Exhibit 10.1 to Edison International’s Form 10-Q for the quarter ended March 31, 2006)*

10.2		Terms and conditions for 2006 long-term compensation awards under the Equity Compensation Plan and 2000 Equity Plan (File No. 1-9936, filed as Exhibit 10.29 to Edison International’s Form 10-K for the year ended December 31, 2005)*

10.3		Southern California Edison Company Named Executive Officer Base Salaries for 2006 (File No. 1-2313, filed as Exhibit 10.51 to Southern California Edison Company’s Form 10-K for the year ended December 31, 2005)*

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: May 8, 2006

SOUTHERN CALIFORNIA EDISON Co - Quarter Report: 2006 March (Form 10-Q)

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