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

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2006

For the transition period from              to             

Commission File Number 1-2313

SOUTHERN CALIFORNIA EDISON COMPANY

(Exact name of registrant as specified in its charter)

(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.

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:

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INDEX

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PART I FINANCIAL INFORMATION

Item 1. Financial Statements

CONSOLIDATED STATEMENTS OF INCOME

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

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CONSOLIDATED BALANCE SHEETS

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

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CONSOLIDATED BALANCE SHEETS

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

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

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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 September 30, 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 September 30, 2006 financial statement presentation.

Derivative Instruments and Hedging Activities

SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale. The normal purchases and sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business SCE enters into contracts for power and gas options, as well as swaps and futures, in order to mitigate its exposure to increases in natural gas and electricity pricing. These transactions are pre-approved by the California Public Utilities Commission (CPUC) or executed in compliance with CPUC-approved procurement plans. The derivative instrument fair values are marked to market at each reporting period. Any fair value changes for recorded derivatives are recorded in purchased-power expense and offset through the provision for regulatory adjustment clauses; therefore, fair value changes do not affect earnings. Hedge accounting is not used for these transactions due to this regulatory accounting treatment.

SCE recorded net unrealized losses of $9 million and $351 million, for the three- and nine-month periods ended September 30, 2006, respectively, compared to net unrealized gains of $504 million and $457 million, for the same periods in 2005, respectively.

Income Taxes

SCE’s effective tax rates from net income was 42% and 40% for the three- and nine-month periods ended September 30, 2006, respectively, as compared to 16% and 24% for the same periods in 2005. The increased effective tax rate resulted primarily from recording a $61 million benefit, including $45 million of interest income, in the third quarter of 2005 relating to a settlement with the Internal Revenue Service (IRS) on tax issues and pending affirmative claims relating to Edison International’s 1991–1993 tax years. Additional increases to the effective tax rate resulted from reductions made to the income tax reserve in 2005 to reflect the issuance of new IRS regulations and progress in settlement negotiations relating to tax audits other than the 1991–1993 IRS audit and adjustments made to tax balances in 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Accounting Pronouncements

A new accounting standard, Statement of Financial Accounting Standards (SFAS) No. 123(R), 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 $11 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, in the first quarter of 2006, mainly to reflect the change in the valuation method for performance shares classified as liability awards and the use of forfeiture estimates.

In April 2006, the Financial Accounting Standards Board (FASB) issued a Staff Position (FSP), FSP FIN 46(R)-6, 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 was effective prospectively beginning July 1, 2006, although companies have until December 31, 2006, to elect retrospective application. SCE has not yet selected a transition method. Applying the guidance of FSP FIN 46(R)-6 had no effect on the financial statements for the three months ended September 30, 2006.

In July 2006, the FASB issued an interpretation (FIN 48) relating to accounting for uncertainty in income taxes. This interpretation clarifies the accounting for uncertain tax positions. An enterprise would be required to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. The effective date for SCE is January 1, 2007. SCE is currently assessing the potential impact of FIN 48 on its financial condition.

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

In September 2006, the FASB issued SFAS No. 158, which amends the accounting by employers for defined benefit pension plans and postretirement benefits other than pensions. SFAS No. 158 requires companies to recognize the overfunded or underfunded status of a defined benefit pension or other postretirement plan as an asset or liability in its balance sheet; the asset or liability is offset through other comprehensive income. SCE will record regulatory assets or liabilities instead of charges or credits to other comprehensive income for its postretirement benefit plans that are recoverable in utility rates, in accordance with accounting principles for rate-regulated enterprises. The standard also requires companies to align the measurement dates for their plans to their fiscal year-ends; SCE already has a fiscal year-end measurement date for all of its postretirement plans. SCE will

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

adopt SFAS No. 158 prospectively on December 31, 2006. Had SFAS No. 158 been effective as of December 31, 2005, SCE would have recorded additional postretirement benefit liabilities of $739 million, additional regulatory assets of $723 million, and a reduction to accumulated other comprehensive income (a component of shareholder’s equity) of $11 million, net of tax. SCE is currently assessing the impact of this standard on its 2006 financial statements.

In September 2006, the SEC issued Staff Accounting Bulletin (SAB) No. 108, which provides interpretive guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. The new guidance requires additional quantitative testing to determine whether a misstatement is material. SCE will implement SAB No. 108 for the filing of its Annual Report on Form 10-K for the year-ended December 31, 2006. SCE is currently assessing the impact, if any, of the adoption of SAB No. 108.

In September 2006, the FASB’s Emerging Issues Task Force (EITF) reached a consensus for Issue No. 06-5, which clarifies the accounting for purchases of life insurance, including corporate-owned life insurance. The new guidance states that policyholders should consider any additional amounts included in the contractual terms of the policy in determining the amount that could be realized under the insurance contract, and specifies that contractual limitations should be considered when determining the realizable amounts. The new guidance is effective January 1, 2007, and retrospective application or a cumulative effect adjustment is permitted to transition to the new guidance. SCE is currently evaluating the impact, if any, of adopting EITF Issue No. 06-5.

Regulatory Assets and Liabilities

Regulatory assets included in the consolidated balance sheets are:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory liabilities included in the consolidated balance sheets are:

Related Party Transactions

Four Edison Mission Energy (EME) subsidiaries have 49% to 50% ownership in partnerships that sell electricity generated by their project facilities to SCE under long-term power purchase agreements with terms and pricing approved by the CPUC. Beginning March 31, 2004, SCE consolidates these projects (see “Variable Interest Entities” disclosed in Note 1 of “Notes to Consolidated Financial Statements” included in SCE’s 2005 Annual Report). These variable interest projects hold $26 million in long-term debt due to EME with an interest rate of 5%, due in October 2008. This is included in long-term debt on the consolidated balance sheet.

SCE holds $153 million in notes receivable from affiliates, due in June 2007 comprising of a $78 million note receivable from EME with an interest rate of London Interbank Offered Rate plus 0.275%; and a 4.4%, $75 million note receivable from Edison International. The $75 million note receivable was previously due from a subsidiary of Edison Capital and was transferred and assigned to Edison International in May 2006. Both notes receivable are included in receivables on the consolidated balance sheet.

Stock-Based Compensation

SCE’s stock-based compensation plans primarily include 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. Edison International has approximately 13.7 million shares remaining for future issuance under its stock-based compensation plans, which are described more fully in Note 2.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Previously, SCE did not capitalize stock-based compensation cost related to both unvested awards and new awards. 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 is capitalizing a portion of its stock-based compensation cost related to both unvested awards and new awards. 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 prior to January 1, 2006, over a period to the date the participant first became eligible for retirement, stock-based compensation expense would have decreased by $1 million for the quarter ended September 30, 2006, would have increased $1 million for the quarter ended September 30, 2005, would have decreased $3 million for the nine months ended September 30, 2006 and would have increased $4 million for the nine months ended September 30, 2005.

Total stock-based compensation expense (reflected in the caption “Other operation and maintenance” on the consolidated statements of income) was $8 million and $15 million for the three months ended September 30, 2006, and 2005, respectively and was $19 million and $38 million for the nine months ended September 30, 2006, and 2005, respectively. The income tax benefit recognized in the income statement was $3 million and $6 million for the three months ended September 30, 2006, and 2005, respectively and was $8 million and $16 million for the nine months ended September 30, 2006, and 2005, respectively. Total stock-based compensation cost capitalized for the three and nine months ended September 30, 2006, was $2 million and $4 million, 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 and nine months ended September 30, 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. The remaining balance of $4 million, net of tax, will no longer be reflected in accumulated other comprehensive income.

Supplemental Cash Flows Information

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 September 30, 2006, $32 million in contributions have been made. Additional funding in 2006 could be lower than anticipated, depending on the funded status at year-end and tax-deductible funding limitations.

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

Expense components are:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Due to the Mohave Generating Station (Mohave) shutdown, SCE has incurred costs for special termination benefits. See “Mohave Shutdown” in Note 7 for further information.

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 September 30, 2006, $18 million in contributions have been made. SCE anticipates that its original expectation will be met by year-end 2006.

Expense components are:

Due to the Mohave shutdown, SCE has incurred costs for special termination benefits. See “Mohave Shutdown” in Note 7 for further information.

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 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 (including amounts capitalized) was $6 million for the three months ended September 30, 2006 and $18 million for the nine months ended September 30, 2006 (including amounts capitalized). 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 nonqualified 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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:

The weighted-average grant-date fair value of options granted during the quarters ended September 30, 2006 and 2005 was $13.72 and $14.23, respectively. The weighted-average grant-date fair value of options granted during the nine months ended September 30, 2006 and 2005 was $14.43 and $11.74, respectively. The total intrinsic value of options exercised during the quarters ended September 30, 2006 and 2005, was $7 million and $16 million, respectively. The total intrinsic value of options exercised during the nine months ended September 30, 2006 and 2005, was $29 million and $38 million, respectively. At September 30, 2006, there was $26 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 two years. The fair value of options vested for the quarters ended September 30, 2006 and 2005 was zero and for the nine months ended September 30, 2006 and 2005 was $3 million and $4 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The amount of cash used to settle stock options exercised was $15 million and $33 million for the quarters ended September 30, 2006 and 2005, respectively, and $60 million and $87 million for the nine months ended September 30, 2006 and 2005, respectively. Cash received from options exercised for the quarters ended September 30, 2006 and 2005, was $8 million and $16 million, respectively, and for the nine months ended September 30, 2006 and 2005, was $31 million and $50 million, respectively. The estimated tax benefit from options exercised for the nine months ended September 30, 2006 and 2005, was $11 million and $15 million, 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 (including amounts capitalized) was $3 million and $13 million for the three months ended September 30, 2006 and 2005, respectively, and $5 million and $30 million for the nine months ended September 30, 2006 and 2005, respectively. Cash used to settle performance shares classified as equity awards was zero for the quarters ended September 30, 2006 and 2005, respectively and $19 million and $10 million for the nine months ended September 30, 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 a risk-free interest rate and an expected volatility rate assumption. 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 a financial data services provider.

Edison International’s risk-free interest rate and expected volatility used to determine the grant date fair values for the 2006 and 2005 performance shares classified as share-based equity awards was 4.1% and 16.2%, respectively, and 2.7% and 27.7%, respectively. The portion of performance shares classified as share-based liability awards are revalued at each reporting period. The risk-free interest rate and expected volatility rate used to determine the fair value as of September 30, 2006 was 4.7% and 16.5%, respectively.

The total intrinsic value of performance shares settled during the quarters ended September 30, 2006 and 2005, including cash paid to settle the performance shares classified as liability awards was zero for both periods. The

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

total intrinsic value of performance shares settled during the nine months ended September 30, 2006 and 2005, was $38 million and $21 million, respectively, which included cash paid to settle the performance shares classified as liability awards for the nine months ended September 30, 2006 and 2005, of $9 million and $5 million, respectively. At September 30, 2006, there was $5 million (based on the September 30, 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 one year. The fair values of performance shares vested during the quarters ended September 30, 2006 and 2005, was zero. The fair values of performance shares vested during the nine-month ended September 30, 2006 and 2005 was less than $1 million and zero, respectively.

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

The weighted-average grant-date fair value of performance shares classified as equity awards granted during the nine months ended September 30, 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:

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.

2006 General Rate Case (GRC) Proceeding

In December 2004, SCE filed its application for a 2006 GRC and subsequently revised its requested 2006 base rate revenue requirement to $3.96 billion, an increase of $465 million over SCE’s 2005 base rate revenue. When a one-time credit of $140 million from an existing balancing account overcollection was applied, SCE’s requested increase was $325 million. SCE also proposed revised base rate revenue increases of $108 million for 2007 and $113 million for 2008.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On May 11, 2006, the CPUC issued its final decision authorizing an increase of $274 million over SCE’s 2005 base rate revenue, retroactive to January 12, 2006. When the one-time credit of $140 million from an existing balancing account overcollection was applied, SCE’s authorized increase was $134 million. The CPUC also authorized increases of $74 million in 2007 and $104 million in 2008. The decision substantially approved SCE’s request to continue its capital investment program for infrastructure replacement and expansion, with authorized revenue in excess of costs for this program subject to refund. In addition, the decision provided for balancing accounts for pensions, postretirement medical benefits and certain incentive compensation expense.

During the second quarter of 2006, SCE implemented the 2006 GRC decision and resolved an outstanding regulatory issue which resulted in a pre-tax benefit of approximately $175 million. The implementation of the 2006 GRC decision retroactive to January 12, 2006 mainly resulted in revenue of $50 million related to the revenue requirement for the period January 12, 2006 through May 31, 2006, partially offset by the implementation of the new depreciation rates resulting in increased depreciation expense of approximately $25 million for the period January 12, 2006 through May 31, 2006. In addition, there was a favorable resolution of a one-time issue related to a portion of revenue collected during the 2001–2003 period for state income taxes. SCE was able to determine through regulatory proceedings (including the 2006 GRC decision) that the level of revenue collected during that period was appropriate, and as a result recorded a pre-tax gain of $135 million.

Environmental Remediation

SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.

SCE believes that it is in substantial compliance with environmental regulatory requirements; however, possible future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that additional costs would be recovered from customers or that SCE’s financial position and results of operations would not be materially affected.

SCE records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, SCE records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts.

SCE’s recorded estimated minimum liability to remediate its 23 identified sites is $84 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 $116 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 32 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to $8 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $35 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 $85 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 September 30, 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.

Federal and State 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. Edison International has also submitted affirmative claims to the IRS and state tax agencies which are being addressed in administrative proceedings. Any benefits would be recorded when a settlement is reached or as part of the implementation of FIN 48.

The IRS Revenue Agent Report for the 1997–1999 audit also asserted deficiencies with respect to a transaction entered into by an SCE subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability company. 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

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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 or who benefited from the manipulation by receiving inflated market prices. SCE is required to refund to customers 90% of any refunds actually realized by SCE net of litigation costs, except for the El Paso Natural Gas Company settlement agreement (see discussion in Note 9 of “Notes to Consolidated Financial Statements” in Edison International’s 2005 Annual Report), and 10% will be retained by SCE as a shareholder incentive.

During the course of the refund proceedings, the FERC ruled that governmental power sellers, like private generators and marketers that sold into the California market, should refund the excessive prices they received during the crisis period. However, on September 21, 2005, the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) ruled that the FERC does not have authority directly to enforce its refund orders against governmental power sellers. The Court, however, clarified that its decision does not preclude SCE or other parties from pursuing civil claims against the governmental power sellers. On March 16, 2006, SCE, Pacific Gas and Electric Company (PG&E) and the California Electricity Oversight Board jointly filed suit in federal court against several governmental power sellers, seeking refunds based on the reduced prices set by the FERC for transactions during the crisis period. SCE cannot predict whether it may be able to recover any additional refunds from governmental power sellers as a result of this suit.

In November 2005, SCE and other parties entered into a settlement agreement with Enron Corporation and a number of its affiliates, most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In April 2006, SCE received an additional distribution on its allowed bankruptcy claim 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 October 2006, SCE received another distribution on its allowed bankruptcy claim of approximately $20 million and 17,040 shares of Portland General Electric Company stock, with an aggregate value of less than $1 million. Additional distributions are expected but SCE cannot currently predict the amount or timing of such distributions.

In December 2005, the FERC approved a settlement agreement among SCE, PG&E, San Diego Gas & Electric, several governmental entities and certain other parties, and Reliant Energy, Inc. and a number of its affiliates. In March 2006, SCE received an additional $61 million as part of the settlement.

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

In November 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-based ratemaking (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.

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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.

Customer Satisfaction

SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service planning group of SCE’s transmission and distribution business unit altered or omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The results of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or penalties for customer satisfaction. SCE recorded aggregate customer satisfaction rewards of $28 million 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 the caption “Other nonoperating deductions” on the income statement 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 disciplining employees and terminating the employment of employees, including several supervisory personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls over data collection and processing. Performance incentive rewards for customer satisfaction expired in 2003 pursuant to the 2003 GRC.

Employee Injury and Illness Reporting

In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE’s employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has 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 and return to ratepayers the $20 million it has already received. Therefore, SCE accrued a $20 million charge in the caption “Other nonoperating deductions” on the income statement 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 remedial action to address the issues identified, including revising its organizational structure and overall program for environmental, health and safety compliance, disciplining employees who committed wrongdoing and terminating an employee. SCE submitted a report on the results of its investigation to the CPUC on December 3, 2004.

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CPUC Investigation

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

In June 2006, the Consumer Protection and Safety Division (CPSD) of the CPUC issued its report regarding SCE’s PBR program, recommending that the CPUC impose various refunds and penalties on SCE. Subsequently, in September 2006, the CPSD and other intervenors, such as the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network filed testimony on these matters recommending various refunds and penalties to be imposed upon SCE. On October 16, 2006, SCE filed testimony opposing the various refund and penalty recommendations of the CPSD and other intervenors. Based on SCE’s proposal for refunds and the combined recommendations of the CPSD and other intervenors, the potential refunds and penalties could range from $32 million up to $396 million. .Evidentiary hearings which will address the planning and meter reading components of customer satisfaction, safety, issues related to SCE’s administration of the survey, and statutory fines associated with those matters are scheduled to take place in the fourth quarter of 2006. A schedule has not been set to address the other components of customer satisfaction, system reliability, and other issues. At this time, SCE cannot predict the outcome of these matters or reasonably estimate the potential amount of any additional refunds, disallowances, or penalties that may be required above the lower end of the range.

ISO Disputed Charges

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. 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 scheduling coordinators in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from scheduling 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 scheduling coordinator 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 by March 2007. 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.

Midway-Sunset Cogeneration Company

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

The claims asserted against Midway-Sunset for refunds related to power sold into the PX and ISO markets, including power sold on behalf of SCE and PG&E, are estimated to be less than $70 million for all periods under

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consideration. Midway-Sunset did not retain any proceeds from power sold into the PX and ISO markets on behalf of SCE and PG&E in excess of the amounts to which it was entitled under the pre-existing power sales contracts, but instead passed through those proceeds to the utilities. Since the proceeds were passed through to the utilities, EME believes that PG&E and SCE are obligated to reimburse Midway-Sunset for any refund liability that it incurs as a result of sales made into the PX and ISO markets on their behalves.

During this period, amounts SCE received from Midway-Sunset were credited to SCE’s customers against power purchase expenses through the ratemaking mechanism in place at that time. SCE believes that any net amounts reimbursed to Midway-Sunset would be substantially recoverable from its customers through current regulatory mechanisms. SCE does not expect any reimbursement to Midway-Sunset to have a material impact on earnings.

Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 in the U.S. District Court for the District of Columbia (District Court), against SCE, among other defendants, arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things, violations of the federal Racketeer Influenced and Corrupt Organization (RICO) statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The complaint claims that the defendants’ actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The complaint seeks damages of not less than $600 million, trebling of that amount, and punitive damages of not less than $1 billion.

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

Pursuant to a joint request of the parties, the D.C. District Court granted a stay of the action on October 5, 2004 to allow the parties to attempt to negotiate a resolution of the issues associated with Mohave with the assistance of a facilitator. An initial, organizational session was held with the facilitator on October 14, 2004 and negotiations are on-going. On July 28, 2005, the District Court issued an order removing the case from its active calendar, subject to reinstatement at the request of any party.

SCE cannot predict the outcome of the 1999 Navajo Nation’s complaint against SCE, the ultimate impact on the complaint of the Supreme Court’s 2003 decision and the on-going litigation by the Navajo Nation against the Government in the related case, or the impact on the facilitated negotiations of SCE’s recently announced decision to discontinue efforts to return Mohave to service.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $10.8 billion. SCE and other owners of San Onofre 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 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.

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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. Recently enacted legislation, which will become effective on January 1, 2007, will amend existing law to accelerate the overall target from 2017 to 2010.

SCE previously entered into a contract with Calpine Energy Services, L.P. to purchase the output of certain existing geothermal facilities in northern California. Under previous CPUC decisions and reporting and compliance methodology, SCE was only able to count procurement pursuant to the Calpine contract towards its annual renewable target to the extent the output was certified as “incremental” by the California Energy Commission. On October 19, 2006, the CPUC issued a decision that revised the reporting and compliance methodology, and permitted SCE to count the entire output pursuant to its Calpine contract towards satisfaction of its annual renewable procurement target thus meeting its renewable procurement obligations for 2003, 2004, 2005 and 2006. The decision also implemented a “cumulative deficit banking” feature which would carry forward and accumulate annual deficits until the deficit has been satisfied at a later time through actual deliveries of eligible renewable energy.

Under the new methodology, SCE could have deficits in meeting its renewable procurement obligations for 2007, but will be in compliance for 2003 through 2006. SCE believes it may be able to demonstrate that it should not be penalized for the 2007 deficit through the CPUC’s flexible compliance rules.

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 renewable procurement targets is $25 million per year. SCE cannot predict whether it will be assessed penalties.

Scheduling Coordinator Tariff Dispute

SCE serves as a scheduling coordinator for the Los Angeles 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 scheduling coordinator charges are billed to the DWP under a FERC tariff that remains subject to dispute. The DWP has paid the amounts billed under protest but requested that the FERC declare that SCE was obligated to serve as the DWP’s scheduling coordinator without charge. The FERC accepted SCE’s

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tariff for filing, but held that the rates charged to the DWP have not been shown to be just and reasonable and thus made them subject to refund and further review by the FERC. As a result, SCE could be required to refund all or part of the amounts collected from the DWP under the tariff. As of September 30, 2006, SCE has accrued a $36 million charge to earnings for the potential refunds. If the FERC ultimately rules that SCE may not collect the scheduling coordinator charges from the DWP and requires the amounts collected to be refunded to the DWP, SCE would attempt to recover the scheduling 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 scheduling coordinator charges cannot be assured.

Settlement Agreement with Duke Energy Trading and Marketing, LLC

On September 21, 2006, the CPUC approved a settlement agreement between SCE and Duke Energy Trading and Marketing, LLC (Duke) that resolved disputes arising from Duke’s termination of certain bilateral power supply contracts in early 2001. Under the settlement, Duke made a $77 million principal and interest payment to SCE in October 2006, which will be refunded to ratepayers through the energy resource recovery account mechanism. The settlement also permitted $58 million in liabilities that SCE had previously recorded with respect to the Duke terminated contracts to be reversed, which resulted in an equivalent benefit recorded by SCE in the third quarter of 2006. The CPUC agreed that these liabilities should not be refunded to ratepayers. The recorded liabilities consisted of $40 million in cash collateral received from Duke in 2000 and $18 million in power purchase payments that SCE, in light of Duke’s termination of the bilateral contracts, withheld for energy delivered by Duke in January 2001.

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 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 June 5, 2006, the Court of Federal Claims lifted the stay on SCE’s case and established a discovery schedule. A Joint Status Report is due on September 7, 2007, regarding further proceedings in this case presumably including establishing a trial date.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel storage installation where all of Unit 1’s spent fuel located at San Onofre is stored. There 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.

There are now sufficient dry casks and modules available to the independent spent fuel storage installation to meet plant requirements through 2008. SCE, as operating agent, plans to continually load casks on a schedule to maintain full core off-load capability for both units in order to meet the plant requirements after 2008 until 2022 (the end of the current Nuclear Regulatory Commission operating license).

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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.

Leases

Unit-specific contracts (signed or modified after June 30, 2003) in which SCE takes virtually all of the output of a facility are generally considered to be leases under accounting rules. At September 30, 2006, SCE had eight power contracts that were classified as operating leases and one capital lease (executed in late 2005). The leases have varying terms, provisions and expiration dates. The capital lease (net commitment of $13 million) is reported as a long-term obligation on the consolidated balance sheet under the caption “Other long-term liabilities.”

Estimated remaining commitments for noncancelable operating leases, including power purchases, vehicles, office space, and other equipment at September 30, 2006 are:

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.

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

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: