SOUTHERN CALIFORNIA EDISON Co - Quarter Report: 2008 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, 2008

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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SOUTHERN CALIFORNIA EDISON COMPANY

INDEX

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GLOSSARY

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

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GLOSSARY (Continued)

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SOUTHERN CALIFORNIA EDISON COMPANY

PART I FINANCIAL INFORMATION

CONSOLIDATED STATEMENTS OF INCOME

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

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SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

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

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SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

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

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SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

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SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Management’s Statement

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary for a fair statement of the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and nine-month periods ended September 30, 2008 are not necessarily indicative of the operating results for the full year.

This quarterly report should be read in conjunction with SCE’s Annual Report to Shareholders incorporated by reference into SCE’s Annual Report on Form 10-K for the year ended December 31, 2007 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 2007 Annual Report on Form 10-K. SCE follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2008 as discussed below in “Margin and Collateral Deposits” and “New Accounting Pronouncements.”

The December 31, 2007 condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Certain prior-period reclassifications have been made to conform to the current year financial statement presentation mostly pertaining to the adoption of FIN No. 39-1.

Cash Equivalents

At September 30, 2008, cash equivalents included U.S. treasury securities and U.S. treasury and government agency money market funds totaling $1.1 billion. At December 31, 2007, cash equivalents included money market funds totaling $83 million. Cash equivalents, with the exception of money market funds, were stated at cost plus accrued interest. The carrying value of cash equivalents approximates fair value due to maturities of less than three months. For further discussion of money market funds, see Note 7.

Margin and Collateral Deposits

Margin and collateral deposits include margin requirements and cash deposited with and received from counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the related positions. See “New Accounting Pronouncements” below for a discussion of the adoption of FIN No. 39-1. In accordance with FIN No. 39-1, SCE presents a portion of its margin and cash collateral deposits net with its derivative positions on its consolidated balance sheets. Amounts recognized for cash collateral provided to others that have been offset against net derivative liabilities totaled $52 million and $2 million at September 30, 2008 and December 31, 2007, respectively.

New Accounting Pronouncements

Accounting Pronouncement Adopted

In April 2007, the FASB issued FIN No. 39-1. This pronouncement permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same

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counterparty under a master netting arrangement. In addition, upon the adoption, companies were permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting agreements. SCE adopted FIN No. 39-1 effective January 1, 2008. The adoption resulted in netting a portion of margin and cash collateral deposits with derivative positions on SCE’s consolidated balance sheets, but had no impact on SCE’s consolidated statements of income. The consolidated balance sheet at December 31, 2007 has been retroactively restated for the change, which resulted in a decrease in margin and collateral deposits of $2 million. The consolidated statements of cash flows for the nine months ended September 30, 2007 has been retroactively restated to reflect the balance sheet changes but had no impact on cash flows from operating activities.

In February 2007, the FASB issued SFAS No. 159, which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings. SCE adopted this pronouncement effective January 1, 2008. The adoption had no impact because SCE did not make an optional election to report additional financial assets and liabilities at fair value.

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. SCE adopted SFAS No. 157 effective January 1, 2008. The adoption did not result in any retrospective adjustments to its consolidated financial statements. The accounting requirements for employers’ pension and other postretirement benefit plans are effective at the end of 2008, which is the next measurement date for these benefit plans. The effective date will be January 1, 2009 for asset retirement obligations and other nonfinancial assets and liabilities which are measured or disclosed on a non-recurring basis. For further discussion, see Note 7.

On October 10, 2008, the FASB issued FSP SFAS No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active.” This position clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. It also reaffirms the notion of fair value as an exit price as of the measurement date. This position was effective upon issuance, including prior periods for which financial statements have not been issued. The adoption had no impact on SCE’s consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

In December 2007, the FASB issued SFAS No. 160, which requires an entity to present minority interest that reflects the ownership interests in subsidiaries held by parties other than the entity, within the equity section but separate from the entity’s equity in the consolidated financial statements. It also requires the amount of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated statement of income; changes in ownership interest be accounted for similarly as equity transactions; and, when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary be measured at fair value. SCE will adopt SFAS No. 160 on January 1, 2009. In accordance with this standard, SCE will reclassify minority interest to a component of shareholder’s equity (at September 30, 2008 this amount was $451 million).

In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. SCE will adopt SFAS No. 161 in the first quarter of 2009. SFAS No. 161 will impact disclosures only and will not have an impact on SCE’s consolidated results of operations, financial condition or cash flows.

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In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements for nongovernmental entities that are presented in conformity with U.S. GAAP. This statement transfers the GAAP hierarchy from the American Institute of Certified Public Accountants Statement on Auditing Standards No. 69, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles” to the FASB. SFAS No. 162 is effective on November 15, 2008. SCE expects that the adoption of this standard will not have an impact on SCE’s consolidated results of operations, financial condition or cash flows.

In September 2008, the FASB issued FSP SFAS No. 133-1 and FIN No. 45-4. FSP SFAS No. 133-1 requires enhanced disclosures by sellers of credit derivatives and amends FASB Interpretation No. 45 (FIN No. 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others,” to require additional disclosure about the current status of the payment/performance risk of a guarantee. The provisions of the FSP that amend SFAS No. 133 and FIN No. 45 are effective for reporting periods ending after November 15, 2008. Since FSP FAS No. 133-1 and FIN No. 45-4 only require additional disclosures, the adoption will not impact SCE’s consolidated financial position, results of operations or cash flows.

Property and Plant

Utility Plant

Utility plant additions, including replacements and betterments, are capitalized. Such costs include direct material and labor, construction overhead, a portion of administrative and general costs capitalized at a rate authorized by the CPUC, and AFUDC. AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction. Currently, AFUDC debt and equity is capitalized during certain plant construction and reported in interest expense and other nonoperating income, respectively. AFUDC is recovered in rates through depreciation expense over the useful life of the related asset.

On November 26, 2007, the FERC issued an order granting incentives on three of SCE’s largest proposed transmission projects, DPV2, Tehachapi Transmission Project (“Tehachapi”), and Rancho Vista Substation Project (“Rancho Vista”). The order permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction of all three projects. On February 29, 2008, the FERC approved SCE’s revision to its Transmission Owner Tariff to collect 100% of construction work in progress (CWIP) for these projects in rate base and earn a return on equity, rather than capitalizing AFUDC. SCE implemented the CWIP rate, subject to refund, on March 1, 2008. For further discussion, see “FERC Transmission Incentives” in Note 5.

Related Party Transactions

During the first quarter of 2008, SCE entered, through a competitive bidding process, a ten-year power-purchase contract with a subsidiary of EME for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the “Walnut Creek” project. The power-purchase agreement was approved by the CPUC on September 18, 2008 and by the FERC on October 2, 2008. Deliveries under the power-purchase agreement are expected to commence in 2013.

Note 2. Liabilities and Lines of Credit

Long-Term Debt

In January 2008, SCE issued $600 million of 5.95% first and refunding mortgage bonds due in 2038. The proceeds were used to repay SCE’s outstanding commercial paper of approximately $426 million and for general corporate purposes. In August 2008, SCE issued $400 million of 5.50% first and refunding mortgage bonds due in 2018. The proceeds were used to repay SCE’s outstanding commercial paper of approximately $110 million

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and borrowings under the credit facility of $200 million, as well as for general corporate purposes. In October 2008, SCE issued $500 million of 5.75% first and refunding mortgage bonds due in 2014. The proceeds were used for general corporate purposes.

The interest rates on one issue of SCE’s pollution control bonds insured by FGIC, totaling $249 million, were reset every 35 days through an auction process. Due to a loss of confidence in the creditworthiness of the bond insurers, there was a significant reduction in market liquidity for auction rate bonds and interest rates on these bonds increased. Consequently, SCE purchased in the secondary market $37 million of its auction rate bonds in December 2007 and the remaining $212 million during the first three months of 2008. In March 2008, SCE converted the issue to a variable rate mode and terminated the FGIC insurance policy. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.

Short-Term Debt

Short-term debt is generally used to finance fuel inventories, balancing account undercollections and general, temporary cash requirements including power-purchase payments. At September 30, 2008, the outstanding short-term debt was $1.56 billion at a weighted-average interest rate of 3.53%. This short-term debt is supported by a $2.5 billion credit line. See below in “Credit Agreements.”

Credit Agreements

The following table summarizes the status of the SCE credit facility at September 30, 2008:

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. A subsidiary of Lehman Brothers Holding, Lehman Brothers Bank, FSB, is one of the lenders in SCE’s credit agreement representing a total commitment of $106 million. In September 2008, Lehman Brothers Bank, FSB declined requests for funding of the most recent borrowings, or approximately $42 million.

Note 3. Income Taxes

SCE’s composite federal and state statutory income tax rate was approximately 40% (net of federal benefit for state income taxes) for all periods presented. SCE’s effective tax rate was 39% and 32% for the three- and nine-month periods ended September 30, 2008, as compared to 35% and 30% for the respective periods in 2007. The higher effective income tax rate for the three months ended September 30, 2008 as compared to the respective period in 2007, was primarily due to two non-deductible expenses recorded in 2008, consisting of a penalty assessed by the CPUC (see “Investigation Regarding Performance Incentives Rewards” in Note 5) and higher lobbying expenses. The higher effective tax rates for the nine months ended September 30, 2008 as compared to the respective period in 2007, were due to both previously-mentioned non-deductible expenses and reductions in the income tax reserve recorded in the first quarter of 2007 to reflect progress made in an administrative appeal process with the IRS related to the income tax treatment of certain costs associated with environmental remediation and to reflect a settlement of state tax audit issues. The previously mentioned factors causing an increase to the 2008 federal and state effective tax rates as compared to 2007 were partially offset by higher software and property-related flow-through deductions recorded in 2008.

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Accounting for Uncertainty in Income Taxes

FIN 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. Edison International has filed affirmative tax claims related to tax positions, which, if accepted, could result in refunds of taxes paid or additional tax benefits for positions not reflected on filed original tax returns. FIN 48 requires the disclosure of all unrecognized tax benefits, which includes the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims.

Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits from January 1, 2008 to September 30, 2008 and the reasons for such changes:

The unrecognized tax benefits in the table above reflects affirmative claims related to timing differences of $1.5 billion and $1.6 billion at September 30, 2008 and January 1, 2008, respectively, but have not met the recognition threshold pursuant to FIN 48 and have been denied by the IRS as part of their examinations. These affirmative claims remain unpaid by the IRS and no receivable has been recorded. Edison International has vigorously defended these affirmative claims in IRS administrative appeals proceedings and these claims are included in the ongoing Global Settlement negotiations.

It is reasonably possible that Edison International could resolve, as part of the Global Settlement, or otherwise, with the IRS, all or a portion of SCE’s unrecognized tax benefits through tax year 2002 within the next 12 months, which could reduce unrecognized tax benefits by up to $1.3 billion.

The total amount of unrecognized tax benefits as of September 30, 2008 and January 1, 2008 that, if recognized, would have an effective tax rate impact is $62 million and $65 million, respectively.

Accrued Interest and Penalties

The total amounts of accrued interest and penalties related to SCE’s income tax reserve were $116 million and $96 million as of September 30, 2008 and January 1, 2008, respectively. The after-tax interest expense recognized and included in income tax expense was $3 million and $12 million for the three- and nine- month periods ended September 30, 2008, respectively.

Tax Positions being Addressed as Part of Active Examinations, Administrative Appeals and the Global Settlement

Edison International is challenging certain IRS deficiency adjustments for tax years 1994 – 1999 with the Administrative Appeals branch of the IRS and Edison International is currently under active IRS examination for

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tax years 2000 – 2006. During the third quarter of 2008, the IRS commenced an examination of tax years 2003 – 2006. In addition, the statute of limitations remains open for tax years 1986 – 1993, which has allowed Edison International to file certain affirmative claims related to these tax years. Tax years 1986 – 2002 are included in the scope of the Global Settlement and tax years 2003 – 2006 are excluded.

Most of these tax positions relate to timing differences and, therefore, any amounts exclusive of any penalties that would be paid if Edison International’s position is not sustained would be deductible on future tax returns filed by Edison International. In addition, Edison International has filed affirmative claims with respect to certain tax years 1986 through 2005 with the IRS and state tax authorities. Any benefits associated with these affirmative claims would be recorded in accordance with FIN 48 which provides that recognition would occur at the earlier of when SCE would make an assessment that the affirmative claim position has a more likely than not probability of being sustained or when a settlement of the affirmative claim is consummated with the tax authority. Certain of these affirmative claims have been recognized as part of the implementation of FIN 48.

Currently, Edison International is under administrative appeals with the California Franchise Tax Board for tax years 1997 – 2002 and under examination for tax years 2003 – 2004. Edison International remains subject to examination by the California Franchise Tax Board for tax years 2005 and forward. Edison International is also subject to examination by other state tax authorities, subject to varying statute of limitations.

Edison International filed amended California Franchise tax returns for tax years 1997 – 2002 to mitigate the possible imposition of new California non-economic substance 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 below. Edison International filed these amended returns under protest retaining its appeal rights.

As previously disclosed, Edison International is currently engaged in settlement negotiations with the IRS to reach a Global Settlement which, if consummated, would resolve outstanding tax disputes for all Edison International subsidiaries, including SCE, for open tax years 1986 through 2002, including certain affirmative claims for unrecognized tax benefits. These negotiations have progressed to the point where Edison International and the IRS have reached nonbinding, preliminary understandings on the material principles for resolution of all issues included in the Global Settlement. Final resolution of such disputes, as part of the Global Settlement, is subject to reaching definitive agreements on final terms and calculations, mutually satisfactory documentation, and review of all or a portion of the Global Settlement by the Staff of the Joint Committee on Taxation, a committee of the United States Congress (the “Joint Committee”). While not assured, Edison International believes that the Global Settlement will be submitted or substantially ready to be submitted to the Joint Committee during the fourth quarter of 2008.

There can be no assurance, however, about the timing of final settlements with the IRS or that such final settlements will be ultimately consummated. Moreover, review by the Joint Committee could result in adjustments to the Global Settlement reached between Edison International and the IRS. The IRS and Edison International may not reach final agreements that implement the preliminary understandings, or they may reach final agreements but conditions to consummating them may not be satisfied.

Balancing Account Over-Collections

In response to an affirmative claim filed by Edison International related to balancing account over-collections, the IRS issued a Notice of Proposed Adjustment in July 2007. This affirmative claim was addressed by the IRS as part of the ongoing IRS examinations and administrative appeals processes. The tax years to which adjustments are made pursuant to this Notice of Proposed Adjustment are included in the scope of the Global Settlement. The cash and earnings impacts of this position are dependent on the ultimate settlement of all open tax issues, including this issue, in these tax years. Edison International expects that resolution of this issue could potentially increase earnings and cash flows within the range of $70 million to $80 million and $300 million to $350 million, respectively.

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Contingent Liability Company

The IRS has asserted deficiencies with respect to a transaction entered into by a former SCE subsidiary which may be considered substantially similar to a Listed Transaction described by the IRS as a contingent liability company for tax years 1997 and 1998. This issue is included in the Global Settlement and is being considered by the Administrative Appeals branch of the IRS where Edison International has been defending its income tax return position with respect to this transaction.

Resolution of Federal and State Income Tax Issues Being Addressed in Ongoing Examinations, Administrative Appeals and the Global Settlement

Edison International continues its efforts to resolve open tax issues through tax year 2002 as part of the Global Settlement. Although the timing for resolving these open tax positions is uncertain, it is reasonably possible that all or a significant portion of these open tax issues through tax year 2002 could be resolved within the next 12 months.

Note 4. Compensation and Benefits Plans

Pension Plans

As of September 30, 2008, SCE has made $6 million in contributions related to 2007 and $37 million related to 2008 and estimates to make $12 million of additional contributions in the last three months of 2008.

Volatile market conditions have affected the value of SCE’s trusts established to fund its future long-term pension benefits. The market value of the investments within the plan trusts declined 22% during the nine months ended September 30, 2008. These benefit plan assets and related obligations are remeasured annually using a December 31 measurement date. Unless the market recovers, reductions in the value of plan assets will result in increased future expense, a change in the pension plan funding status from overfunded to underfunded and increased future contributions. Changes in the plan’s funded status will affect the assets and liabilities recorded on the balance sheet in accordance with SFAS No. 158. Due to SCE’s regulatory recovery treatment, the recognition of the funded status is offset by regulatory liabilities and assets. In the 2009 GRC, SCE requested recovery of and continued balancing account treatment for amounts contributed to these trusts. The Pension Protection Act of 2006 establishes new minimum funding standards and prohibits plans underfunded by more than 20% from providing lump sum distributions and adopting amendments that increase plan liabilities.

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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Postretirement Benefits Other Than Pensions

As of September 30, 2008, SCE has made no contributions related to 2007 and $14 million related to 2008 and estimates to make $26 million of additional contributions in the last three months of 2008.

Volatile market conditions have affected the value of SCE’s trust established to fund its future other postretirement benefits. The market value of the investments within the plan trust declined 21% during the nine months ended September 30, 2008. These benefit plan assets and related obligations are remeasured annually using a December 31 measurement date. Unless the market recovers, reductions in the value of plan assets will result in increased future expense, an increase in the plan underfunded status and increased future contributions. Changes in the plan’s funded status will affect the assets and liabilities recorded on the balance sheet in accordance with SFAS No. 158. Due to SCE’s regulatory recovery treatment, the recognition of the funded status is offset by regulatory liabilities and assets. In the 2009 GRC, SCE requested recovery of and continued balancing account treatment for amounts contributed to this trust.

Expense components are:

Stock-Based Compensation

During the first quarter of 2008, Edison International granted its 2008 stock-based compensation awards, which included stock options, performance shares, deferred stock units and restricted stock units. Total stock-based compensation expense (reflected in the caption “Other operation and maintenance” on the consolidated statements of income) was $2 million and $5 million for the three months ended September 30, 2008 and 2007, respectively, and was $11 million and $22 million for the nine months ended September 30, 2008 and 2007, respectively. The income tax benefit recognized in the consolidated statements of income was $1 million and $2 million for the three months ended September 30, 2008 and 2007, respectively, and was $5 million and $7 million for the nine months ended September 30, 2008 and 2007, respectively. Total stock-based compensation cost capitalized was less than $1 million and $1 million for the three months ended September 30, 2008 and 2007, respectively, and was $2 million and $4 million for the nine months ended September 30, 2008 and 2007, respectively.

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Stock Options

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

Stock options granted in 2008 do not accrue dividend equivalents.

The amount of cash used to settle stock options exercised was $3 million and $7 million for the three months ended September 30, 2008 and 2007, respectively, and $23 million and $111 million for the nine months ended September 30, 2008 and 2007, respectively. Cash received from options exercised was $2 million and $3 million for the three months ended September 30, 2008 and 2007, respectively, and $11 million and $50 million for the nine months ended September 30, 2008 and 2007, respectively. The estimated tax benefit from options exercised was $1 million and $2 million for the three months ended September 30, 2008 and 2007, respectively, and $5 million and $25 million for the nine months ended September 30, 2008 and 2007, respectively.

Note 5. Commitments and Contingencies

The following is an update to SCE’s commitments and contingencies. See Note 6 of “Notes to Consolidated Financial Statements” included in SCE’s 2007 Annual Report on Form 10-K for a detailed discussion.

Lease Commitments

During the second quarter of 2008, SCE entered into power-purchase contracts which are classified as operating leases. The contract terms range from 10 to 20 years. The delivery of energy under one of these contracts is not expected to commence until 2018. These additional commitments are currently estimated to be: remainder of 2008 – $4 million, 2009 – $14 million, 2010 – $15 million, 2011 – $15 million, 2012 – $15 million and thereafter – $828 million.

During the third quarter of 2008, SCE entered into power-purchase contracts which are classified as capital leases. The contract terms are 20 years. The delivery of energy under these contracts is expected to commence in 2010. These additional commitments are currently estimated to be: 2010 – $32 million, 2011 – $119 million, 2012 – $119 million and thereafter – $2.6 billion. The estimated executory costs and interest expense associated with these additional commitments are $699 million and $988 million, respectively. The total additional estimated net commitments are $1.2 billion.

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Other Commitments

During the first nine months of 2008, SCE entered into service contracts associated with uranium enrichment and fuel fabrication. As a result, SCE’s additional fuel supply commitments are estimated to be: 2009 – $51 million, 2010 – $54 million, 2011 – $98 million, 2012 – $146 million and thereafter – $671 million.

During the second quarter of 2008, SCE entered into a new power-purchase contract. The delivery of energy under this contract is expected to commence in August 2010 with a 10 year term. SCE’s additional commitments upon commencement are estimated to be: 2010 – $188 million, 2011 – $335 million, 2012 – $341 million and thereafter – $2.7 billion.

Indemnities

Indemnity Provided as Part of the Acquisition of Mountainview

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

Mountainview Filter Cake Indemnity

Mountainview owns and operates a power plant in Redlands, California. The plant utilizes water from on-site groundwater wells and City of Redlands (City) recycled water for cooling purposes. Unrelated to the operation of the plant, this water contains perchlorate. The pumping of the water removes perchlorate from the aquifer beneath the plant and concentrates it in the plant’s wastewater treatment “filter cake.” Use of this impacted groundwater for cooling purposes was mandated by Mountainview’s CEC permit. Mountainview has indemnified the City for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City’s solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this guarantee.

Other Indemnities

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

Contingencies

In addition to the matters disclosed in these Notes, SCE is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. SCE believes the outcome of these other proceedings will not materially affect its consolidated results of operations or liquidity.

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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 consolidated financial position and results of operations would not be materially affected.

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

As of September 30, 2008, SCE’s recorded estimated minimum liability to remediate its 24 identified sites was $47 million, of which $14 million was related to San Onofre. This remediation liability is undiscounted. 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 $167 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 30 immaterial sites whose total liability ranges from $3 million (the recorded minimum liability) to $9 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $32 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 $42 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

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

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $11 million to $31 million. Recorded costs for the 12 months ended September 30, 2008 were $32 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

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consolidated results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

Federal and State Income Taxes

Edison International remains subject to examination and administrative appeals by the IRS for various tax years. See Note 3 for further details.

FERC Transmission Incentives

On November 16, 2007, the FERC issued an order granting incentives on three of SCE’s largest proposed transmission projects:

The order also grants a higher return on equity on SCE’s entire transmission rate base in SCE’s next FERC transmission rate case for SCE’s participation in the CAISO. In September 2008, the FERC accepted SCE’s revisions to its Transmission Owner Tariff, with a requested effective date of March 1, 2009 subject to refund and settlement procedures. In addition, the order permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction, also known as CWIP, of all three projects and 100% recovery of prudently-incurred abandoned plant costs for DPV2 and Tehachapi, if either or both of these projects are cancelled due to factors beyond SCE’s control.

In June 2008, the FERC rejected petitions filed by certain parties, including the CPUC, to address the CAISO higher return and the ROE project adders. In August 2008, the CPUC filed an appeal of the FERC incentives order at the DC Circuit Court of Appeals.

FERC Construction Work in Progress Mechanism

On December 21, 2007, SCE filed a revision to its Transmission Owner Tariff to collect 100% of CWIP in rate base for its Tehachapi, DPV2, and Rancho Vista projects. In the CWIP filing, SCE proposed a rate adjustment ($45 million or a 14.4% increase) to SCE’s currently authorized base transmission revenue requirement to be made effective on March 1, 2008 and later adjusted for amounts actually spent in 2008 through a new balancing account mechanism. The rate adjustment represents actual expenditures from September 1, 2005 through November 30, 2007, projected expenditures from December 1, 2007 through December 31, 2008, and a ROE (which includes the ROE adders approved for Tehachapi, DPV2 and Rancho Vista). The rate adjustment is based on a projection that SCE will spend a total of approximately $244 million, $27 million, and $181 million for Tehachapi, DPV2, and Rancho Vista, respectively, from September 1, 2005 through the end of 2008. The 2008 DPV2 expenditure forecast is limited to projected consulting and legal costs associated with SCE’s continued efforts to obtain regulatory approvals necessary to construct the DPV2 Project. On February 29, 2008, the CWIP filing was approved and SCE implemented the CWIP rate on March 1, 2008, subject to refund on the limited issue of whether SCE’s proposed ROEs are reasonable. On March 28, 2008, the CPUC filed a Petition for Rehearing with the FERC on the FERC’s acceptance of SCE’s proposed ROE for CWIP. Briefs addressing the appropriate ROE were filed by SCE and intervenors in May 2008. In addition, in the order, SCE was directed by

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FERC to make a compliance filing to provide greater detail on the costs reflected in CWIP rates for 2008. SCE made the compliance filing on March 31, 2008. On April 21, 2008, the CPUC filed a protest of the compliance filing at FERC and requested an evidentiary hearing to be set to further review the costs. SCE filed a response to the CPUC’s protest on May 6, 2008 arguing that the FERC should deny the CPUC’s request for a further hearing. SCE cannot predict the outcome of the matters in this proceeding.

SCE filed its 2009 update to its CWIP rate adjustment on October 31, 2008. SCE proposed a reduction to its CWIP revenue requirement from $45 million to $39 million to be effective on January 1, 2009.

Investigation Regarding Performance Incentives Rewards

SCE was eligible under the CPUC-approved PBR mechanism to earn rewards or incur penalties based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee safety reporting, and system reliability. SCE conducted investigations into its performance under the PBR mechanism and reported to the CPUC certain findings of misconduct and misreporting related to the first two components of the PBR program. Following SCE’s reporting, the CPUC opened its own investigation of SCE’s activities relative to the PBR mechanism.

CPUC Decision

On September 18, 2008, the CPUC adopted a decision in the first phase of its investigation into SCE’s incentives claimed under the CPUC-approved PBR mechanism that allowed SCE to earn rewards or incur penalties for the period 1997 – 2003 based on its performance in comparison to CPUC-approved standards of customer satisfaction and employee safety reporting. The adopted decision required SCE to refund $28 million and $20 million related to customer satisfaction and employee safety reporting incentives, respectively; and further required SCE to forego claimed incentives of $20 million and $15 million related to customer satisfaction and employee safety reporting, respectively. The decision also required SCE to refund $33 million for employee bonuses and imposed a statutory penalty of $30 million. During the third quarter, SCE recorded a charge of $49 million, after-tax, reflected primarily in “Other nonoperating deductions” in the consolidated statements of income related to this decision.

System Reliability

In light of the problems uncovered with the components of the PBR mechanism discussed above, SCE conducted an investigation into the third PBR standard, system reliability, for the years 1997 – 2003. SCE received $8 million in reliability incentive awards for the period 1997 – 2000 and had applied for a reward of $5 million for 2001. For 2002, SCE’s data indicated that it earned no reward and incurred no penalty. For 2003, based on the application of the PBR mechanism, SCE determined that it would incur a penalty of $3 million and accrued a charge for that amount in 2004. On February 28, 2005, SCE provided its final investigation report to the CPUC concluding that the reliability reporting system was working as intended. System reliability incentives will be addressed in the second phase of the CPUC’s investigation. SCE served its opening testimony in the second phase in September 2007. In that testimony, SCE presented evidence that its PBR system reliability results were valid. The schedule for the second phase of the investigation has been deferred until November 21, 2008. SCE cannot predict the outcome of the second phase but does not expect a material financial statement impact.

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

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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. On March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. On May 25, 2007, the FERC issued a procedural order granting the rehearing application for the limited purpose of allowing the FERC to give it further consideration. In a future order, FERC may deny the rehearing request or grant the requested relief in whole or in part. SCE believes that the most recent substantive FERC order correctly allocates responsibility for these ISO charges. However, SCE cannot predict the final outcome of the rehearing. If a subsequent regulatory decision changes the allocation of responsibility for these charges, and SCE is required to pay these charges as a transmission owner, SCE may seek recovery in its reliability service rates. SCE cannot predict whether recovery of these charges in its reliability service rates would be permitted.

Four Corners CPUC Emissions Performance Standard Ruling

The CPUC adopted a GHG emission performance standard, effective January 2007. In January 2008, SCE filed a petition with the CPUC seeking clarification that the emission performance standard would not apply to capital expenditures required by existing agreements among the owners at Four Corners. The CPUC issued a proposed decision finding that the emission performance standard was not intended to apply to capital expenditures at Four Corners requested by SCE in its General Rate Case for the period 2007 – 2011. On October 23, 2008, the Assigned Commissioner and Administrative Law Judge issued a ruling withdrawing the proposed decision and seeking additional comment on whether the finding in the proposed decision should be changed and whether SCE should be allowed to recover such capital expenditures. SCE estimates that its share of capital expenditures approved by the owners at Four Corners since the GHG emission performance standard decision was issued in January 2007 is approximately $43 million, of which approximately $8 million had been expended through September 30, 2008. The ruling also directs SCE to explain why certain information was not included in its petition and why the failure to include such information should not be considered misleading in violation of CPUC rules. SCE cannot predict the outcome of this proceeding or estimate the amount, if any, of penalties or disallowances that may be imposed.

Midway-Sunset Cogeneration Company

San Joaquin Energy Company, a wholly owned subsidiary of EME, owns a 50% general partnership interest in Midway-Sunset, which owns a 225 MW cogeneration facility near Fellows, California. Midway-Sunset is a party to several proceedings pending at the FERC because Midway-Sunset was a seller in the PX market 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 market, Midway-Sunset is potentially liable for refunds to purchasers in these markets.

On December 20, 2007, Midway-Sunset entered into a settlement agreement in the amount of $86 million (including interest) with SCE, PG&E, SDG&E and certain California state parties to resolve Midway-Sunset’s liability in the FERC refund proceedings. Midway-Sunset concurrently entered into a separate agreement with SCE and PG&E that provides for pro-rata reimbursement to Midway-Sunset by the two utilities of the portions of the agreed to refunds that are attributable to sales made by Midway-Sunset for the benefit of the utilities (Midway-Sunset did not retain any proceeds from power sold into the PX market 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). The settlement, which had been approved previously by the CPUC, was approved by the FERC on April 2, 2008.

During the period in which Midway-Sunset’s generation was sold into the PX market, amounts SCE received from Midway-Sunset for its pro-rata share of such sales were credited to SCE’s customers against power purchase expenses through the ratemaking mechanism in place at that time. During the second quarter of 2008,

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SCE reimbursed Midway-Sunset for its pro-rata share of the Midway-Sunset liability in the amount of approximately $43 million. In addition, SCE, as party to the Midway-Sunset settlement agreement, received a $20 million generator refund. The amount reimbursed to and received from Midway-Sunset (net amount of $23 million) were charged/refunded to ratepayers through regulatory mechanisms. As a result, the transactions associated with the Midway-Sunset settlement agreement did not impact earnings.

Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 in the D.C. District Court against SCE, among other defendants, arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things, violations of the federal RICO statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The complaint claims that the defendants’ actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The complaint seeks damages of not less than $600 million, trebling of that amount, and punitive damages of not less than $1 billion. In March 2001, the Hopi Tribe was permitted to intervene as an additional plaintiff but has not yet identified a specific amount of damages claimed.

In April 2004, the D.C. District Court denied SCE’s motion for summary judgment and concluded that a 2003 U.S. Supreme Court decision in an on-going related lawsuit by the Navajo Nation against the U.S. Government did not preclude the Navajo Nation from pursuing its RICO and intentional tort claims. In September 2007, the Federal Circuit reversed a lower court decision on remand in the related lawsuit, finding that the U.S. Government had breached its trust obligation in connection with the setting of the royalty rate for the coal supplied to Mohave. Subsequently, the Federal Circuit denied the U.S. Government’s petition for rehearing. On October 1, 2008, the U.S. Supreme Court granted the U.S. Government’s petition seeking review of the Federal Circuit’s September 2007 decision. A decision from the U.S. Supreme Court is expected in mid-2009.

Pursuant to a joint request of the parties, the D.C. District Court granted a stay of the action in October 2004 to allow the parties to attempt to negotiate a resolution of the issues associated with Mohave with the assistance of a facilitator. In a joint status report filed on November 9, 2007, the parties informed the court that their mediation efforts had terminated and subsequently filed a joint motion to lift the stay. The parties have also filed recommendations for a scheduling order to govern the anticipated resumption of litigation. The Court granted the motion to lift the stay on March 6, 2008, reinstating the case to the active calendar, but has deferred setting an overall schedule for the action pending a determination of disputes concerning the discoverability of certain Navajo documents. SCE cannot predict the outcome of the Navajo Nation’s and Hopi Tribe’s complaints against SCE or the ultimate impact on these complaints of the Supreme Court’s 2003 decision and the on-going litigation by the Navajo Nation against the U.S. Government in the related case.

Nuclear Insurance

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

Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. Beginning October 29, 2008, the maximum deferred premium for each nuclear incident is approximately $118 million per reactor, but not more than approximately $18 million per reactor may be charged in any one year for each incident. The maximum deferred premium per reactor and the yearly assessment per reactor for each nuclear incident will be adjusted for inflation at least once every five years beginning August 20, 2003. The most recent inflation adjustment took effect on October 29, 2008. Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately $35 million per incident in any one year.

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Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further revenue.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $45 million per year. Insurance premiums are charged to operating expense.

Palo Verde Nuclear Generating Station Inspections

The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. The combination of the results of the first and third special inspections caused the NRC to undertake an additional oversight inspection of Palo Verde. This additional inspection, known as a supplemental inspection, was completed in December 2007. In addition, Palo Verde was required to take additional corrective actions based on the outcome of completed surveys of its plant personnel and self-assessments of its programs and procedures. The NRC and APS defined and agreed to inspection and survey corrective actions that the NRC embodied in a Confirmatory Action Letter, which was issued in February 2008. APS is presently on track to complete the corrective actions required to close the Confirmatory Action Letter by mid-2009. Palo Verde operation and maintenance costs (including overhead) increased in 2007 by approximately $7 million from 2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in 2007 dollars) over the two year period 2008 – 2009, from 2007 recorded costs including overhead costs. SCE is unable to estimate how long SCE will continue to incur these costs. In the 2009 GRC, SCE requested recovery of, and two-way balancing account treatment for, Palo Verde operation and maintenance expenses including costs associated with these corrective actions. If approved, this would provide for recovery of these costs over the three-year GRC cycle.

Procurement of Renewable Resources

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

SCE filed its latest compliance report in August 2008. Through the use of flexible compliance rules, SCE demonstrated full compliance for the procurement year 2007 and forecasted full compliance for the procurement years 2008 to 2020. It is unlikely that SCE will have 20% of its annual electricity sales procured from renewable resources by 2010. However, SCE may still meet the 20% target by utilizing the flexible compliance rules. SCE continues to engage in several renewable procurement activities including formal solicitations approved by the CPUC, bilateral negotiations with individual projects and other initiatives.

Under current CPUC decisions, potential penalties for SCE’s inability to achieve its renewable procurement objectives for any year will be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance 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

Pursuant to the Amended and Restated Exchange Agreement, SCE serves as a scheduling coordinator for the DWP over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund

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for FERC-authorized scheduling coordinator and line loss charges incurred by SCE on the DWP’s behalf. The scheduling coordinator charges had been billed to the DWP under a FERC tariff that was subject to dispute. The DWP has paid the amounts billed under protest but requested that the FERC declare that SCE was obligated to serve as the DWP’s scheduling coordinator without charge. The FERC accepted SCE’s tariff for filing, but held that the rates charged to the DWP have not been shown to be just and reasonable and thus made them subject to refund and further review by the FERC.

In January 2008, an agreement between SCE and the DWP was executed settling the dispute discussed above. The settlement had been previously approved by the FERC in July 2007. The settlement agreement provides that the DWP will be responsible for line losses and SCE would be responsible for the scheduling coordinator charges. During the fourth quarter of 2007, SCE reversed and recognized in earnings (under the caption “Purchased power” in the consolidated statements of income) $30 million of an accrued liability representing line losses previously collected from the DWP that were subject to refund. As of December 31, 2007, SCE had an accrued liability of approximately $22 million (including $3 million of interest) representing the estimated amount SCE will refund for scheduling coordinator charges previously collected from the DWP. SCE made its first refund payment on February 20, 2008 and the second refund payment was made on February 27, 2008. SCE previously received FERC approval to recover the scheduling coordinator charges from all transmission grid customers through SCE’s transmission rates and on December 11, 2007, the FERC accepted SCE’s proposed transmission rates reflecting the forecast levels of costs associated with the settlement. Upon signing of the agreement in January 2008, SCE recorded a regulatory asset and recognized in earnings the amount of scheduling coordinator charges to be collected through rates. On July 8, 2008, the FERC approved the refund report.

Spent Nuclear Fuel

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its obligation to begin acceptance of spent nuclear fuel 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. In a Joint Status Report filed on July 1, 2008, the parties requested a trial date in mid-November 2008. On August 6, 2008, the Court set a trial date of April 14 – 28, 2009.

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 and some of Unit 2 and 3’s spent fuel is stored. SCE, as operating agent, plans to transfer fuel from the Unit 2 and 3 spent fuel pools to the independent storage installation on an as-needed basis to maintain full core off-load capability for Units 2 and 3. There are now sufficient dry casks and modules available at the independent spent fuel storage installation to meet plant requirements through the end of 2008. SCE plans to add storage capacity incrementally to meet the plant requirements until 2022 (the end of the current NRC operating license).

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

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Note 6. Supplemental Cash Flows Information

SCE’s supplemental cash flows information is:

Note 7. Fair Values Measurements

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an “exit price” in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability should reflect the entity’s nonperformance risk. In addition, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical asset and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under SFAS No. 157 are:

SCE’s assets and liabilities carried at fair value primarily consist of derivative contracts, SCE nuclear decommissioning trust investments and money market funds. Derivative contracts primarily relate to power and gas and include contracts for forward physical sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange traded or over-the-counter traded.

The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. SCE’s Level 2 derivatives primarily consist of natural gas swaps and natural gas physical trades for which SCE obtains the applicable Henry Hub and basis forward market prices from the New York Mercantile Exchange.

Level 3 includes the majority of SCE’s derivatives, including over-the-counter options, bilateral contracts, and capacity and QF contracts. The fair value of these SCE derivatives is determined using uncorroborated broker

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quotes and models which may require SCE to extrapolate short-term observable inputs in order to calculate fair value. Level 3 also includes derivatives that trade infrequently (such as firm transmission rights and CRRs in the California market and over-the-counter derivatives at illiquid locations), derivatives with counterparties that have significant non-performance risks, and long-term power agreements. For illiquid firm transmission rights and CRRs, SCE reviews objective criteria related to system congestion on a quarterly basis and other underlying drivers and adjusts fair value when SCE concludes a change in objective criteria would result in a new valuation that better reflects the fair value. Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. In circumstances where SCE cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, SCE continues to assess valuation methodologies used to determine fair value.

The SCE nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed-income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed-income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information.

The following table sets forth financial assets and liabilities that were accounted for at fair value as of September 30, 2008 by level within the fair value hierarchy.

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The following table sets forth a summary of changes in the fair value of Level 3 derivative contracts, net for the three- and nine- month periods ended September 30, 2008.

Nuclear Decommissioning Trusts

SCE is collecting in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent trusts. Funds collected, together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.

Trust investments (at fair value) include: