Form 10-Q

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 a non-accelerated filer. See definition of “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:

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

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

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state 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, 2007 are not necessarily indicative of the operating results for the full year.

This quarterly report should be read in conjunction with Edison International’s Annual Report to Shareholders incorporated by reference into Edison International’s Annual Report on Form 10-K for the year ended December 31, 2006 filed with the Securities and Exchange Commission.

Edison International’s significant accounting policies were described in Note 1 of “Notes to Consolidated Financial Statements” included in its 2006 Annual Report on Form 10-K. Edison International follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for uncertain tax positions (discussed below in “New Accounting Pronouncements”).

On April 1, 2006, EME received, as a capital contribution from its affiliate, Edison Capital, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. EME accounted for this acquisition at Edison Capital’s historical cost as a transaction between entities under common control. As a result of this capital contribution, Edison International’s nonutility power generation segment now includes the wind assets and biomass power project previously owned by Edison Capital and included in the financial services segment.

Certain prior-period amounts were reclassified to conform to the September 30, 2007 financial statement presentation. Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.

Edison International computes EPS using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International’s participating securities are stock based compensation awards payable in common shares, including stock options, performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares. Stock options awarded during the period 2003 through 2006 received dividend equivalents. Stock options awarded prior to 2002 and after 2006 were granted without a dividend equivalent feature. As a result of meeting a performance trigger, the options granted in 1998 and 1999 began earning dividend equivalents in 2006. EPS was computed as follows:

Stock-based compensation awards to purchase 37,057 and 1,949,574 shares of common stock for the three months ended September 30, 2007 and 2006, respectively, and 59,577 and 1,944,045 shares of common stock for the nine months ended September 30, 2007 and 2006, respectively were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares, therefore, the effect would have been antidilutive.

Edison International’s eligible subsidiaries are included in Edison International’s consolidated federal income tax and combined state tax returns. Edison International has tax-allocation and payment agreements with certain of its subsidiaries. For subsidiaries other than SCE, the right of a participating subsidiary to receive or make a payment and the amount and timing of tax-allocation payments are dependent on the inclusion of the subsidiary in the consolidated income tax returns of Edison International and other factors including the consolidated taxable income of Edison International and its includible subsidiaries, the amount of taxable income or net operating losses and other tax items of the participating subsidiary, as well as the other subsidiaries of Edison International. There are specific procedures regarding allocations of state taxes. Each subsidiary is eligible to

receive tax-allocation payments for its tax losses or credits only at such time as Edison International and its subsidiaries generate sufficient taxable income to be able to utilize the participating subsidiary’s losses in the consolidated tax return of Edison International. Under an income tax-allocation agreement approved by the CPUC, SCE’s tax liability is computed as if it filed a separate return.

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

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

In July 2006, the FASB issued FIN 48 which clarifies the accounting for uncertain tax positions. FIN 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. Edison International adopted FIN 48 effective January 1, 2007. Implementation of FIN 48 resulted in a cumulative-effect adjustment that increased retained earnings by $250 million upon adoption. Edison International will continue to monitor and assess new income tax developments including the IRS’ challenge of the sale/leaseback and lease/leaseback transactions.

In July 2006, the FASB issued an FSP on accounting for a change in timing of cash flows related to income taxes generated by a leverage lease transaction (FSP FAS 13-2). Edison International adopted FSP FAS 13-2 effective January 1, 2007. The adoption did not have a material impact on Edison International’s consolidated financial statements.

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

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

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. Edison International will adopt SFAS No. 157 on January 1, 2008. Edison International is currently evaluating the impact of adopting SFAS No. 157 on its financial statements.

SCE bills certain sales and use taxes levied by state or local governments to its customers. Included in these sales and use taxes are franchise fees, which SCE pays to various municipalities (based on contracts with these municipalities) in order to operate within the limits of the municipality. SCE bills these franchise fees to its customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SCE’s ability to collect from the customer, are accounted for on a gross basis and reflected in electric utility revenue and other operation and maintenance expense. SCE’s franchise fees billed to customers and recorded as electric utility revenue were $34 million and $37 million for the three months ended September 30, 2007 and 2006, respectively, and $81 million and $84 million for the nine months ended September 30, 2007 and 2006. When SCE acts as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. Amounts billed to and collected from customers for these taxes are being remitted to the taxing authorities and are not recognized as revenue.

At September 30, 2007, Edison International held various variable rate demand notes related to short-term cash management activities. The interest rate process for these securities allow for a resetting of interest rates related to changes in terms and/or credit quality, similar to cash and cash equivalents. In accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, these notes are classified as short-term investments. As of September 30, 2007, the notes were classified as available-for-sale securities and were recorded at fair value in the amount of $168 million. There were no outstanding notes as of December 31, 2006. Sales of the notes were $7.0 billion and $4.5 billion for the nine-month periods ended September 30, 2007 and 2006, respectively. Purchases of the notes were $7.2 billion and $4.5 billion for the nine-month periods ended September 30, 2007, and 2006, respectively. There were no realized or unrealized gains or losses. The consolidated statements of cash flows was revised to reflect the 2006 sales and purchases activity on a gross basis.

In addition, at September 30, 2007 and December 31, 2006, EME had classified all marketable debt securities as held-to-maturity and carried at amortized cost plus accrued interest which approximated their fair value. Gross unrealized holding gains and losses were not material.

EME’s held-to-maturity securities, which all mature within one year, consisted of the following:

Stock options, performance shares, deferred stock units and, beginning in 2007, restricted stock units have been granted under Edison International’s long-term incentive compensation programs. Edison International usually

does not issue new common stock for equity awards settled. Rather, a third party is used to facilitate the exercise of stock options and the purchase and delivery of outstanding common stock for settlement of option exercises, performance shares, and restricted stock units. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Deferred stock units granted to management are settled in cash, not stock and represent a liability.

On April 26, 2007, Edison International’s shareholders approved a new incentive plan (the 2007 Performance Incentive Plan) that includes stock-based compensation. No additional awards will be granted under Edison International’s prior stock-based compensation plans on or after April 26, 2007, and all future issuances will be made under the new plan. The maximum number of shares of Edison International’s common stock that may be issued or transferred pursuant to awards under the new incentive plan is 8.5 million shares, plus the number of any shares subject to awards issued under Edison International’s prior plans and outstanding as of April 26, 2007, which expire, cancel or terminate without being exercised or shares being issued. As of September 30, 2007, Edison International has approximately 8.4 million shares remaining for future issuance under its stock-based compensation plan. For further discussion see “Stock-Based Compensation” in Note 5.

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

The changes in net unrealized (gains) losses on economic hedging activities primarily resulted from changes in SCE’s gas hedge portfolio mix as well as the movements in the natural gas futures market. The changes in net realized losses on economic hedging activities primarily resulted from a more stable natural gas market in 2007.

As of September 30, 2007, Edison International’s long-term debt maturities and sinking fund requirements for the next five years are: remainder of 2007 – $221 million; 2008 – $18 million; 2009 – $175 million; 2010 – $314 million; 2011 – $13 million. As discussed below, these amounts have been updated primarily to reflect EME’s financing activities completed during the second quarter of 2007.

On May 7, 2007, EME completed a private offering of $1.2 billion of its 7.00% senior notes due May 15, 2017, $800 million of its 7.20% senior notes due May 15, 2019 and $700 million of its 7.625% senior notes due May 15, 2027. EME will pay interest on the senior notes on May 15 and November 15 of each year, beginning on November 15, 2007.

The senior notes are EME’s senior unsecured obligations, ranking equal in right of payment to all EME’s existing and future senior unsecured indebtedness, and will be senior to all EME’s future subordinated indebtedness. EME’s secured debt and its other secured obligations are effectively senior to the senior notes to the extent of the value of the assets securing such debt or other obligations. None of EME’s subsidiaries have guaranteed the senior notes and, as a result, all of the existing and future liabilities of EME’s subsidiaries are effectively senior to the senior notes.

EME used the net proceeds of the offering of the senior notes, together with cash on hand, to purchase approximately $587 million of EME’s outstanding 7.73% senior notes due 2009, to purchase $1 billion of Midwest Generation’s 8.75% second priority senior secured notes due 2034, to repay the outstanding amount ($328 million) of Midwest Generation’s senior secured term loan facility, and to make a dividend payment of $899 million to MEHC which enabled MEHC to purchase $796 million of its 13.5% senior secured notes due 2008. The net proceeds of the offering of the senior notes, together with cash on hand, were also used to pay related tender premiums, consent fees, and accrued interest. Edison International recorded a total pre-tax loss of approximately $241 million (approximately $148 million after tax) on early extinguishment of debt during the second quarter of 2007.

On June 25, 2007, MEHC redeemed in full its senior secured notes. As a result of the redemption, EME is no longer subject to financial and investment restrictions that were contained in the indenture pursuant to which the senior secured notes were issued. Following the redemption, MEHC no longer files reports with the U.S. Securities and Exchange Commission.

On May 7, 2007, EME amended its existing $500 million secured credit facility, increasing the total borrowings available there under to $600 million.

On June 29, 2007, Midwest Generation completed a refinancing of indebtedness by amending and restating its existing credit facility. The refinancing provided, among other things, for: (a) the option to extend the maturity of the working capital facility by up to two years, subject to the satisfaction of enumerated conditions, (b) the option to grant first or second priority liens to eligible hedge counterparties, (c) the release of collateral in the event that the unsecured debt of Midwest Generation is rated investment grade, (d) a reduction in the interest rate applicable to the working capital facility, and (e) a modification of covenants, including the incurrence of indebtedness covenant and the financial covenants. The refinancing also eliminates the term loan facility.

After giving effect to the refinancing, the working capital facility interest rate was lowered to LIBOR + 0.55% from LIBOR + 1.50%. The working capital facility matures in 2012, with an option to extend for up to two years. Also, as part of the refinancing, Midwest Generation’s financial covenants were modified, with its debt to capitalization ratio to be no greater than 0.60 to 1.

Midwest Generation intends to use its secured working capital facility to provide credit support for its hedging activities and for general working capital purposes. Midwest Generation may also support its hedging activities by granting first or second priority liens to eligible hedge counterparties. As of September 30, 2007, $3 million had been utilized under the working capital facility.

Edison International’s composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. Edison International’s effective tax rate from continuing operations was 36% and 31% for the three- and nine-month periods ended September 30, 2007, respectively, as compared to 40% and 39% for the respective periods in 2006. The decreased effective tax rate was caused primarily by year over year changes in property related flow-through items at SCE, lower interest expense related to lower tax reserves at SCE in 2007, as compared to 2006, as a result of implementing FIN 48, and increased tax credits at EME in 2007. In addition, the nine-month variance included reductions made to the income tax reserve during the first quarter of 2007 to reflect progress in an administrative appeal process with the IRS related to SCE’s income tax treatment of costs associated with environmental remediation and due to reductions made to the income tax reserves during the second quarter of 2007 to reflect settlement of a state tax issue related to the April 2007 State Notice of Proposed Adjustment discussed below.

The net liability recorded for uncertain tax positions was $324 million and $221 million as of September 30, 2007 and the date of adoption (January 1, 2007) of FIN 48, respectively. The net liability as of September 30, 2007 and the date of adoption consists of $406 million and $512 million, respectively, of unrecognized tax benefits, partially offset by $82 million and $290 million, respectively, of recognized tax benefits representing the expected settlement outcome of affirmative claims made or expected to be made that meet the recognition requirement pursuant to FIN 48. The change in the unrecognized tax benefits from the date of adoption reflects decreases of $27 million from positions taken in 2007 and $79 million from positions taken for prior periods. The total amount of unrecognized tax benefits as of September 30, 2007 and the date of adoption that, if recognized, would affect the effective tax rate was $209 million and $189 million, respectively.

The unrecognized tax benefits, as of September 30, 2007 and the date of adoption, do not reflect affirmative claims of $1.6 billion and $1.7 billion, respectively. These claims consist of $28 million and $71 million representing the difference between the amount filed on amended tax returns and the amount recognized pursuant to FIN 48 as of September 30, 2007 and the date of adoption, respectively, and $1.6 billion of claims for both periods which have been filed on amended tax returns but have not met the recognition requirement pursuant to FIN 48, the majority of which have been denied as part of an IRS examination. These affirmative claims remain unpaid by the IRS and no receivable has been accrued. Edison International is vigorously defending these affirmative positions in IRS administrative appeals.

The total amount of accrued interest and penalties was $159 million and $119 million as of September 30, 2007 and the date of adoption, respectively. The total amount of interest expense and penalties recognized in income tax expense for the three-months ended September 30, 2007 was $14 million. The total benefit recognized in income tax expense for the nine months ended September 30, 2007 was $15 million.

Edison International remains subject to examination and administrative appeals by the IRS for tax years 1994 – present. Edison International is challenging certain IRS examination adjustments for tax years 1994 – 1999 with the Administrative Appeals branch of the IRS and Edison International is currently under IRS examination for tax years 2000 – 2002. In addition, the statute of limitations remains open for tax years 1986 – 1993 for certain affirmative claims.

In July 2007, Edison International received a Notice of Proposed Adjustment from the IRS on an affirmative claim position involving the taxability of balancing account over-collections. This issue is part of the ongoing IRS examinations and administrative appeals process. The tax years affected by this Notice of Proposed Adjustment remain subject to examination and administrative appeals. The cash and earnings impacts of this position are dependent on the ultimate settlement of all issues in these tax years. Edison International expects earnings and cash flows to increase within the range of $70 million to $80 million and $300 million to $325 million, respectively.

In April 2007, Edison International received a Notice of Proposed Adjustment from the California Franchise Tax Board for tax years 2001 and 2002 and is currently protesting the deficiencies asserted. Edison International remains subject to examination by the California Franchise Tax Board for tax years 2003 – present. Edison International is also subject to examination by select state tax authorities, with varying statute of limitations. Some state jurisdictions follow the federal statute for comparable issues.

Edison International continues its efforts to resolve open tax issues through 2002 with the IRS and various State authorities. The timing for resolving these open tax positions is uncertain, but it is reasonably possible that all or some portion of these open tax positions could be resolved in the next 12 months.

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

Edison International previously disclosed in Note 5 of “Notes to Consolidated Financial Statements” included in its 2006 Annual Report on Form 10-K that it expects to contribute approximately $66 million to its pension plans in 2007. As of September 30, 2007, Edison International had made $58 million in contributions related to 2006 and $30 million related to 2007 and estimates to make $14 million of additional contributions in the last three months of 2007. Expected contribution funding in 2007 could vary from anticipated amounts, depending on the funded status at year-end and tax-deductible funding limitations.

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

Edison International previously disclosed in Note 5 of “Notes to Consolidated Financial Statements” included in its 2006 Annual Report on Form 10-K that it expects to contribute approximately $42 million to its postretirement benefits other than pension plans in 2007. As of September 30, 2007, Edison International had made no contributions related to 2006 and $16 million related to 2007 and estimates to make $37 million of additional contributions in the last three months of 2007. Expected contribution funding in 2007 could vary from anticipated amounts, depending on the funded status at year-end and tax-deductible funding limitations.

Total stock-based compensation expense (reflected in the caption “Other operation and maintenance” on the consolidated statements of income) was $9 million and $14 million for the three months ended September 30, 2007 and 2006, respectively, and was $38 million and $37 million for the nine months ended September 30, 2007 and 2006, respectively. The income tax benefit recognized in the consolidated statements of income was $4 million and $6 million for the three months ended September 30, 2007 and 2006, respectively, and was $15 million for both nine-month periods ended September 30, 2007 and 2006. Total stock-based compensation cost capitalized was $1 million and $2 million for the three months ended September 30, 2007 and 2006, respectively, and was $4 million for both nine-month periods ended September 30, 2007 and 2006.

Stock options granted in 2007 do not accrue dividend equivalents except for options granted to Edison International’s Board of Directors.

The amount of cash used to settle stock options exercised was $12 million and $23 million for the three months ended September 30, 2007 and 2006, respectively, and was $174 million and $91 million for the nine months ended September 30, 2007 and 2006, respectively. Cash received from options exercised was $5 million and $12 million for the three months ended September 30, 2007 and 2006, respectively, and was $77 million and $45 million for the nine months ended September 30, 2007 and 2006, respectively. The estimated tax benefit

from options exercised was $3 million and $4 million for the three months ended September 30, 2007 and 2006, respectively, and was $39 million and $18 million for the nine months ended September 30, 2007 and 2006, respectively.

The following is an update to Edison International’s commitments. See Note 6 of “Notes to Consolidated Financial Statements” included in Edison International’s 2006 Annual Report for a detailed discussion.

SCE entered into new power-purchase contracts during the first nine months of 2007. These additional commitments are currently estimated to be $13 million for the remainder of 2007, $186 million for 2008, $114 million for 2009, $73 million for 2010, $41 million for 2011 and $198 million thereafter.

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

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

SCE entered into service contracts associated with uranium enrichment and fuel fabrication during the first nine months of 2007. As a result, SCE’s additional fuel supply commitments are estimated to be $82 million for the remainder of 2007, zero for 2008, $14 million for 2009, $8 million for 2010, $7 million for 2011 and $40 million thereafter.

Midwest Generation and EME Homer City have entered into additional fuel purchase commitments during the first nine months of 2007. These additional commitments are currently estimated to be $15 million for the remainder of 2007, $215 million in 2008, $203 million in 2009, and $86 million in 2010.

Midwest Generation has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers), which extends through 2011. Midwest Generation’s commitments under this contract are based on actual coal purchases from the PRB. Accordingly, contractual obligations for transportation are based on coal volumes set forth in fuel supply contracts. The increase in transportation commitments entered into during the first nine months of 2007 relates to additional volumes of fuel purchases using the terms of existing transportation agreements. These additional commitments are currently estimated to be $18 million for the remainder of 2007, $111 million for 2008, $76 million for 2009, and $77 million for 2010.

At September 30, 2007, EME’s subsidiaries had firm commitments to spend approximately $193 million during the remainder of 2007, $175 million in 2008 and $5 million in 2009 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects. Also included are expenditures for dust collection and mitigation systems and environmental improvements. These expenditures are planned to be financed by cash on hand, cash generated from operations or existing subsidiary credit agreements.

At September 30, 2007, EME had entered into agreements with vendors securing 522 wind turbines (1,185 MW) with remaining commitments of $123 million in 2007, $518 million in 2008, $416 million in 2009, and

$49 million in 2010. At September 30, 2007, EME had recorded wind turbine deposits of $260 million included in other long-term assets in its consolidated balance sheet.

In addition, EME had entered into an agreement to purchase five gas turbines and related equipment for an aggregate purchase price of approximately $145 million. During the second and third quarters of 2007, EME entered into change order agreements with the seller of the turbines that returned the deposits previously made and cancelled the remaining commitments. During the third quarter of 2007, EME received refunds totaling $112 million with respect to the five turbines.

Edison International’s subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts included performance guarantees, guarantees of debt and indemnifications.

In connection with the sale-leaseback transactions that EME has entered into related to the Powerton and Joliet Stations in Illinois, the Collins Station in Illinois, and the Homer City facilities in Pennsylvania, EME and several of its subsidiaries entered into tax indemnity agreements. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities. In connection with the termination of the Collins Station lease in April 2004, Midwest Generation continues to have obligations under the tax indemnity agreement with the former lease equity investor.

In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability related to this indemnity.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement has a five-year term with an automatic renewal provision (subject to the right of either party to terminate). Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were approximately 208 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at September 30, 2007. Midwest Generation had recorded a $64 million liability at September 30, 2007 related to this matter.

The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than projected.

In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a claim from the sellers. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. EME has not recorded a liability related to this indemnity.

The asset sale agreements for the sale of EME’s international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At September 30, 2007, EME had recorded a liability of $96 million related to these matters.

In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. EME has not recorded a liability related to these indemnities.

EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project’s power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. In addition, a subsidiary of EME has guaranteed the obligations of Sycamore Cogeneration Company under its project power sales agreement to repay capacity payments to the project’s power purchaser in the event that the project unilaterally terminates its performance or reduces its electric power producing capability during the term of the power sales agreement. The obligations under the indemnification agreements as of September 30, 2007, if payment were required, would be $83 million. EME has not recorded a liability related to these indemnities.

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

Mountainview owns and operates a power plant in Redlands, California. The plant utilizes water from on-site groundwater wells and City of Redlands (City) recycled water for cooling purposes. Unrelated to the operation of the plant, this water contains perchlorate. The pumping of the water removes perchlorate from the aquifer beneath the plant and concentrates it in the plant’s wastewater treatment “filter cake.” Use of this impacted groundwater for cooling purposes was mandated by Mountainview’s California Energy Commission permit. Mountainview has indemnified the City for cleanup or 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.

Edison International 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. Edison International’s obligations under these agreements may be limited in terms of time and/or amount, and in some instances Edison International 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. Edison International has not recorded a liability related to these indemnities.

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

EMMT participated successfully in the first Illinois power procurement auction, held in September 2006 according to rules approved by the Illinois Commerce Commission, and entered into two load requirements services contracts through which it is delivering electricity, capacity and specified ancillary, transmission and load following services necessary to serve a portion of Commonwealth Edison’s residential and small commercial customer load, using contracted supply from Midwest Generation.

On March 16, 2007, the Office of the Attorney General for the State of Illinois filed a complaint at the FERC alleging that the prices resulting from the Illinois auction resulted in unjust and unreasonable rates under the Federal Power Act and that participating wholesale sellers in the Illinois auction had colluded and manipulated the results of the auction. All successful participants in the Illinois auction, including EMMT, were named as respondents. The Office of the Attorney General asked the FERC to order refunds and to revoke the respondents’ market-based rate pricing authority.

On July 24, 2007, Midwest Generation and EMMT, along with other power generation companies and utilities, entered into a settlement agreement with the Illinois Attorney General. The settlement was subject to the passage of legislation which will, among other things, establish a new Illinois Power Agency to manage future power procurement for the Illinois regulated utilities, Commonwealth Edison and Ameren (beginning with the planning year June 1, 2009 through May 31, 2010). The settlement legislation was passed by the Illinois legislature on July 26, 2007, and was signed by the Governor of Illinois on August 28, 2007.

As part of the settlement, Midwest Generation has agreed to pay $25 million over three years toward approximately $1 billion in utility customer rate relief and startup costs of the new Illinois Power Agency. The remainder is to be funded by subsidiaries of Exelon Corporation, subsidiaries of Ameren, Dynegy Holdings Inc., and Mid-American Energy Company. Also as part of the settlement, all auction-related complaints filed by the Illinois Attorney General at the FERC, the Illinois Commerce Commission and in the Illinois courts have been dismissed. The private class action lawsuits described below remain pending.

Midwest Generation made a payment of $7.5 million in September 2007 and is obligated to make monthly payments of $750,000 beginning in January 2008 and continuing until the total commitment has been funded. These payments are non-refundable; however, Midwest Generation’s obligations to make the monthly payments will cease if, at any time prior to December 2009, Illinois imposes an electric rate freeze or an additional tax on generators.

On April 4, 2007, EMMT was served with a complaint filed in the Circuit Court of Cook County, Illinois, by Saul R. Wexler, individually and on behalf of an alleged class of similarly situated electric ratepayers in Illinois, against Commonwealth Edison, Ameren, and all of the successful participants in the Illinois auction, including EMMT. The lawsuit alleges that the defendants, including EMMT, colluded and conspired to manipulate the auction results by price-fixing. The lawsuit seeks unspecified damages. On April 26, 2007, the defendants transferred the complaint to the U.S. District Court for the Northern District of Illinois, Eastern Division. On June 4, 2007, the defendants filed a motion to dismiss the case.

On March 30, 2007, David Schafer, Tim Perry, Pat Martin and Michael Murray, individually and on behalf of an alleged class of similarly situated electric ratepayers in Illinois, filed a complaint in the Circuit Court of Cook County, Illinois, against Commonwealth Edison, Ameren, and all of the successful participants in the Illinois auction, including EMMT. EMMT has not been formally served in the case. The lawsuit alleges that the defendants, including EMMT, colluded and conspired to manipulate the auction results by price-fixing. The lawsuit seeks unspecified damages. On April 26, 2007, the defendants transferred the complaint to the U.S. District Court for the Northern District of Illinois, Eastern Division. On June 4, 2007, the defendants filed a motion to dismiss the case.

The Wexler case and the Schafer case have been consolidated into a single proceeding by the U.S. District Court for the Northern District of Illinois, Eastern Division. The defendants’ motions to dismiss the case remain pending.

EME believes that EMMT’s actions in regard to the Illinois auction were appropriate and lawful and intends to defend vigorously both of the matters described above. However, at this time EME cannot predict the outcome of these matters.

Edison International 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.

Edison International 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 Edison International’s financial position and results of operations would not be materially affected.

Edison International 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. Edison International 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, Edison International records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts.

As of September 30, 2007, Edison International’s recorded estimated minimum liability to remediate its 41 identified sites at SCE (24 sites) and EME (17 sites related to Midwest Generation) was $72 million, $69 million of which was related to SCE. Edison International’s other subsidiaries have no identified remediation sites. The ultimate costs to clean up Edison International’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. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $132 million, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 31 immaterial sites whose total liability ranges from $2 million (the recorded minimum liability) to $7 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $30 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 $66 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

Edison International’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 Edison International 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.

Edison International 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, 2007 were $22 million.

Based on currently available information, Edison International 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 incurred at SCE, Edison International 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.

the Administrative Appeals branch of the IRS and Edison International is currently under IRS examination for tax years 2000 – 2002. In addition, the statute of limitations remains open for tax years 1986 – 1993 for certain affirmative claims.

The IRS has asserted deficiencies in federal corporate income taxes with respect to tax years 1994 – 1999. Many of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of penalties), if any, would be deductible on future tax returns of Edison International. In addition, Edison International has also submitted affirmative claims to the IRS and state tax agencies. Any benefits associated with these affirmative claims would be recorded at the earlier of when Edison International believes that the affirmative claim position has a more likely than not probability of being sustained or when a settlement is consummated. Certain affirmative claims have been recorded as part of the implementation of FIN 48.

As part of a nationwide challenge of certain types of lease transactions, the IRS has raised issues about the deferral of income taxes associated with Edison Capital’s cross-border, leveraged leases.

The IRS is challenging Edison Capital’s foreign power plant and electric locomotive sale/leaseback transactions entered into in 1993 and 1994 (Replacement Leases, which the IRS refers to as a sale-in/lease-out or SILO). The IRS is also challenging Edison Capital’s foreign power plant and electric transmission system lease/leaseback transactions entered into in 1997 and 1998 (Lease/Leaseback, which the IRS refers to as a lease-in/lease-out or LILO).

Edison Capital also entered into a lease/service contract transaction in 1999 involving a foreign telecommunication system (Service Contract, which the IRS also refers to as a SILO). The IRS has not yet asserted any adjustment for the Service Contract but Edison International has been responding to data requests from the IRS about the transaction as part of an IRS examination of tax years 2000 – 2002. The following table summarizes estimated federal and state income taxes deferred from these leases as of December 31, 2006. Repayment of these deferred taxes would be accelerated if the IRS prevails:

As of September 30, 2007, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $489 million. The IRS also seeks a 20% penalty on any sustained tax adjustment.

Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law in effect at the time the transactions were entered into, and it is vigorously defending its tax treatment of these leases. Written protests were filed to appeal the audit adjustments for the tax years under appeal asserting that the IRS’s position misstates material facts, misapplies the law and is incorrect. This matter is now being considered by the Administrative Appeals branch of the IRS.

In addition, the payment of taxes, interest and penalties could have a significant impact on earnings and cash flow. In order to commence litigation in certain forums, Edison International must make payments of disputed taxes, along with interest and any penalties asserted by the IRS, and thereafter pursue refunds. On May 26, 2006, Edison International paid $111 million of the taxes, interest and penalties for tax year 1999 followed by a refund claim for the same amount. The cash payment was funded by Edison Capital and accounted for as a deposit which will be refunded with interest to the extent Edison International prevails. Since the IRS did not act on this refund claim within six months from the date the claim was filed, it is deemed denied. Edison International is prepared to take legal action to assert its refund claim if an acceptable settlement cannot be reached with the IRS.

A number of other cases involving these kinds of lease transactions are pending before various courts. The first case involving a LILO was decided against the taxpayer on summary judgment in the Federal District Court in North Carolina. That taxpayer has appealed that decision to the Fourth Circuit Court of Appeals.

Edison International expects to file a refund claim for any taxes, interest and penalties paid pursuant to the administrative appeals settlement of the 1994 – 1996 tax years related to assessed tax deficiencies and penalties assessed on the Replacement Leases. These payments would be treated as a deposit. Edison International may make additional payments related to other tax years to preserve its litigation rights, although, at this time, the amount and timing of these additional payments is uncertain. At this time, Edison International is unable to predict the impact of the ultimate resolution of these matters.

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

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

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

violation of the Energy Policy Act of 2005 and the FERC’s rules regarding market behavior, all with respect to certain bidding practices previously employed by EMMT. EMMT is engaged in discussions with the staff to explore the possibility of resolution of this matter. Discussions to date have been constructive and may lead to a settlement agreement acceptable to both parties. Should these discussions not result in a settlement and a formal proceeding commenced, EMMT will be entitled to contest any alleged violations before the FERC and an appropriate court. EME believes that EMMT has complied with all applicable laws and regulations and intends to contest vigorously any allegation of violation.

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

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

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

On October 19, 2007, the FERC issued an order in the Bonneville case, concluding that the Ninth Circuit’s decision required the FERC to vacate its previous orders compelling governmental sellers during the California energy crisis to pay refunds and to release to governmental suppliers the amounts that had been withheld from, as well as collateral posted, from such suppliers for power delivered during the energy crisis. In its order, the FERC also expressly recognized that civil lawsuits against the governmental suppliers could provide an alternative refund remedy for SCE and the other California utilities. It also left open the possibility that a court with jurisdiction over the matter could order the ISO or PX to retain collateral. SCE cannot predict at this time the impact of the FERC’s order or whether SCE may be able to recover any additional refunds from governmental power sellers as a result of the pending lawsuits.

$12 million and 55,465 shares of Portland General Electric Company stock, with an aggregate value of less than $2 million. In October 2007, SCE received an additional distribution on its allowed bankruptcy claim of approximately $10 million. Additional distributions are expected but SCE cannot currently predict the amount or timing of such distributions.

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

SCE was eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability. SCE conducted investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings of misconduct and misreporting as further discussed below.

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

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

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

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

disclosed in the investigative findings to the CPUC that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid incidents.

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

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

In light of the problems uncovered with the PBR mechanisms discussed above, SCE conducted an investigation into the third PBR metric, system reliability for the years 1997 – 2003. SCE received $8 million in reliability incentive awards for the period 1997 – 2000 and 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, 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.

On June 15, 2006, the CPUC instituted a formal investigation to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer satisfaction, employee safety and system reliability portions of PBR. In June 2006, the CPSD of the CPUC issued its report regarding SCE’s PBR program, recommending that the CPUC impose various refunds and penalties on SCE. Subsequently, in September 2006, the CPSD and other intervenors, such as the CPUC’s DRA and The Utility Reform Network, filed testimony on these matters recommending various refunds and penalties be imposed on SCE. In their testimony, the various parties made refund and penalty recommendations that range up to the following amounts: refund or forgo $48 million in rewards for customer satisfaction, impose $70 million penalties for customer satisfaction, refund or forgo $35 million in rewards for employee safety, impose $35 million penalties for employee safety, impose $102 million in statutory penalties, refund $84 million of amounts collected in rates for employee bonuses (“results sharing”), refund $4 million of miscellaneous survey expenses, and require $10 million of new employee safety programs. These recommendations total up to $388 million. On October 16, 2006, SCE filed testimony opposing the various refund and penalty recommendations of the CPSD and other intervenors.

On October 1, 2007, a POD was released ordering SCE to refund $136 million, plus interest, and pay a penalty of $40 million. In addition, the POD requires SCE to forgo an additional $35 million in rewards for which it would have otherwise been eligible. Included in the amount to be refunded or forgone is $48 million related to customer satisfaction rewards, $35 million related to employee safety rewards, and $77 million related to results sharing. The decision requires that the proposed results sharing refund of $77 million (based on year 2000 data) be adjusted for attrition and escalation which increases the result sharing refund to $88 million. After the result sharing adjustment is made, the total amount SCE would be required to refund increases to $136 million, before interest. Interest to date, based on amounts collected for customer satisfaction, safety incentives and results sharing, including escalation and attrition adjustments, would add an additional $26 million to this amount. On October 31, 2007, SCE appealed the POD to the CPUC.

potential loss and is accruing interest (approximately $15 million as of September 30, 2007) on collected amounts that SCE has proposed to refund to customers.

The system reliability component of PBR was not addressed in the POD. Pursuant to an earlier order in the case, system reliability incentives will be addressed in a second phase of the proceeding, which commenced with the filing of SCE’s opening testimony in September 2007. In that testimony, SCE confirmed that its PBR system reliability results, which reflected rewards of $13 million for 1997 through 2002 and a penalty of $3 million in 2003 were valid. The CPSD has requested an indefinite suspension of the schedule for the second phase of the proceeding pending resolution of the appeals of the POD. SCE cannot predict the outcome of the second phase.

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. On March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. On May 25, 2007, the FERC issued a procedural order granting the rehearing application for the 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 provide assurance as to the final outcome of the rehearing. If a subsequent regulatory decision changes the allocation of responsibility for these charges, and SCE is required to pay these charges as a transmission owner, SCE may seek recovery in its reliability service rates. SCE cannot provide any assurance that recovery of these charges in its reliability service rates would be permitted.

Edison Capital has a net leveraged lease investment of $55 million, before deferred taxes, in three aircraft leased to American Airlines. Although American Airlines reported a profit in 2006, it reported net losses for a number of years prior to 2006. A default in the leveraged lease by American Airlines could result in a loss of some or all of Edison Capital’s lease investment. At September 30, 2007, American Airlines was current in its lease payments to Edison Capital.

Edison Capital also has a net leveraged lease investment of $39 million, before deferred taxes, in a 1,500-MW natural gas-fired cogeneration plant leased to Midland Cogen. During 2005, Midland Cogen wrote down the book value of its power plant as a result of substantial increases in long-term natural gas prices. A default of the lease could result in a loss of some or all of Edison Capital’s lease investment. At September 30, 2007, Midland Cogen was current in its payments under the lease.

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

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

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

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

On July 31, 2007, the US EPA issued a NOV to Midwest Generation and Commonwealth Edison. In the NOV, the US EPA alleges that, beginning in the early 1990’s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the Clean Air Act, including alleged requirements to obtain a construction permit and to install Best Available Control Technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the Clean Air Act. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. Midwest Generation, the US EPA, and the DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. As a result, Midwest Generation is investigating the claims made by the US EPA in the NOV and has identified several defenses which it will raise if the government files suit. At this early stage in the process, Midwest Generation cannot predict the effect this matter may have on its facilities, its results of operations or financial position.

On August 13, 2007, Midwest Generation and Commonwealth Edison received a letter signed by several Chicago-based environmental action groups stating that, in light of the NOV, the groups are examining the possibility of filing a citizen suit against Midwest Generation and Commonwealth Edison based presumably on the same or similar theories advanced by the US EPA in the NOV.

By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating with one another in responding to the NOV.

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

In April 2004, the District Court denied SCE’s motion for summary judgment and concluded that a 2003 U.S. Supreme Court decision in an ongoing 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 the 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. The Federal Circuit decision is potentially subject to further review but it is unknown at this time whether the U.S. Government will pursue such review.

Pursuant to a joint request of the parties, the District Court granted a stay of the action on October 5, 2004 to allow the parties to attempt to negotiate a resolution of the issues associated with Mohave with the assistance of a facilitator. An initial organizational session was held with the facilitator on October 14, 2004 and negotiations are ongoing. On July 28, 2005, the District Court issued an order removing the case from its active calendar, subject to reinstatement at the request of any party. On April 30, 2007, the District Court, in light of the duration of the stay, issued a minute order directing that the parties file a joint status report and recommendation for future proceedings no later than June 1, 2007. In their June 1, 2007 joint status report, the parties advised the District Court of the history and status of their settlement efforts, including the potential for further discussions. Following its receipt of the status report, the District Court continued the stay and directed the parties to file a further joint status report by October 5, 2007. Based on the information presented in the October 5, 2007 joint status report, the District Court directed the parties to file another status report by November 9, 2007, with recommendations for further proceedings.

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

Federal law limits public liability claims from a nuclear incident to $10.8 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($300 million). The balance is covered by the industry’s retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site. Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. The current maximum deferred premium for each nuclear incident is $101 million per reactor, but not more than $15 million per reactor may be charged in any one year for each incident. The maximum deferred premium per reactor and the yearly assessment per reactor for each nuclear incident will be adjusted for inflation on a 5-year schedule. The next inflation adjustment will occur no later than August 20, 2008. Based on its ownership interests, SCE could be required to pay a maximum of $201 million per nuclear incident. However, it would have to pay no more than $30 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to $46 million per year. Insurance premiums are charged to operating expense.

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

The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. A follow-up to the first inspection resulted in a finding that Palo Verde had not established adequate measures to ensure that certain corrective actions were effective to address the root cause of the event. The second recent inspection identified five violations, but none of those resulted in increased NRC scrutiny. The most recent inspection, concerning the failure of an emergency backup generator at Palo Verde Unit 3 identified a violation that, combined with the first inspection finding, will cause the NRC to undertake additional oversight inspections of Palo Verde. In addition, Palo Verde will be required to take additional corrective actions based on the outcome of recently completed surveys of its plant personnel and self-assessments of its programs and procedures. These corrective actions are currently being developed in conjunction with the NRC, and are forecast to be completed by the end of 2007. These corrective actions will increase costs to both Palo Verde and its co-owners, including SCE. SCE cannot calculate the total increase in costs until the corrective actions are finalized, but presently estimates that operation and maintenance costs at Palo Verde will increase by approximately $30 million (nominal) over the three year period 2007 – 2009, including overhead costs. SCE also is unable to estimate how long SCE will continue to incur these costs.

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

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

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

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

Pursuant to the Amended and Restated Exchange Agreement, SCE serves as a scheduling coordinator for the DWP over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund for FERC-authorized scheduling coordinator charges incurred by SCE on the DWP’s behalf. The scheduling coordinator charges are billed to the DWP under a FERC tariff that remains subject to dispute. The DWP has paid the amounts billed under protest but requested that the FERC declare that SCE was obligated to serve as the DWP’s scheduling coordinator without charge. The FERC accepted SCE’s tariff for filing, but held that the rates charged to the DWP have not been shown to be just and reasonable and thus made them subject to refund and further review by the FERC. In September 2006, SCE and the DWP agreed to a term sheet that would settle this dispute, among others surrounding the Exchange Agreement. The settlement was approved by the FERC on July 27, 2007 and is expected to be approved by the City of Los Angeles prior to year end 2007. As of September 30, 2007, SCE has an accrued liability of $49 million (including $7 million of interest) representing total charges collected that are subject to refund. Under the settlement terms, SCE would refund to the DWP the scheduling coordinator charges collected, with an offset for contract losses, and will be able to recover the scheduling coordinator charges from all transmission grid customers. In a FERC filing dated October 30, 2007, SCE forecasted that the refund to the DWP for the scheduling coordinator charges under the settlement would be made on January 1, 2008 and would be approximately $20 million. The amount is proposed to be recovered from all transmission grid customers through SCE’s transmission rates on that date.

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its obligation to begin acceptance of spent nuclear fuel by January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to 0.1¢-per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE’s failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. The case was stayed through April 7, 2006. On June 5, 2006, the Court of Federal Claims lifted the stay on SCE’s case and established a discovery schedule. A Joint Status Report is due on February 22, 2008, regarding further proceedings in this case, presumably including the setting of a trial date.

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

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

Edison International’s accumulated other comprehensive income (loss) consists of:

SFAS No. 158 – pension and other postretirement benefits – net of tax relates to “Pension Plans” and “Postretirement Benefits Other Than Pensions” discussed in Note 5.

Unrealized losses on cash flow hedges, net of tax, at September 30, 2007, included unrealized losses on commodity hedges related to Midwest Generation and EME Homer City futures and forward electricity contracts that qualify for hedge accounting. These losses arise because current forecasts of future electricity prices in these markets are greater than the contract prices. The change from unrealized gains to unrealized losses during the nine months ended September 30, 2007 resulted from an increase in market prices for power.

As EME’s hedged positions for continuing operations are realized, approximately $20 million, after tax, of the net unrealized gains on cash flow hedges at September 30, 2007 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which a cash flow hedge is designated is through December 31, 2010.

Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. Edison International recorded net gains (losses) associated with EME’s activities of approximately $(13) million and $7 million during the third quarters of 2007 and 2006, respectively, and $(23) million and $(10) million during the nine months ended September 30, 2007 and 2006, respectively, representing the amount of cash flow hedges’ ineffectiveness for continuing operations, reflected in nonutility power generation revenue in Edison International’s consolidated income statements.

During the first nine months of 2007, Edison International accrued $25 million in connection with EME’s purchase price of wind projects acquired in 2007 due upon completion of construction. During the first nine months of 2006, EME accrued $11 million in connection with the purchase price of the Wildorado wind project paid upon completion of the project in April 2007. Also in 2006, EME received a capital contribution of $76 million in the form of ownership interests in a portfolio of wind projects and a small biomass project.

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

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

Edison International’s reportable business segments include its electric utility operation segment (SCE), a nonutility power generation segment (MEHC-parent only and EME), and a financial services provider segment (Edison Capital). Edison International evaluates performance based on net income.

On April 1, 2006, EME received as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. As a result of this capital contribution, Edison International’s nonutility power generation segment now includes the wind assets and biomass power project previously owned by Edison Capital. The resulting change in the structure of Edison International’s internal organization and in accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” prior periods have been restated to conform to Edison International’s new business segment definition.

Segment information for the three and nine months ended September 30, 2007 and 2006 was:

EME previously owned a 220 MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by the project’s counterparty, a subsidiary of TXU Europe Group plc. Following a claim for termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the remaining amount of the settlement after payment of creditor claims. As creditor claims have been settled, EME received payments of £61 million (approximately $106 million) in the first quarter of 2006, £9 million (approximately $16 million) in April 2006 and £4 million (approximately $8 million) in January 2007. The after-tax income attributable to the Lakeland project was none for both the third quarters of 2007 and 2006 and $5 million and $83 million for the nine months ended September 30, 2007 and 2006, respectively. Beginning in 2002, EME reported the Lakeland project as discontinued operations and accounts for its ownership of Lakeland Power on the cost method (earnings are recognized as cash is distributed from the project).

For both periods presented, the results of EME’s project discussed above have been accounted for as discontinued operations in the consolidated financial statements in accordance with SFAS No. 144.

For the three months ended September 30, 2007, and 2006, there was no revenue from discontinued operations and pre-tax loss was $5 million and $2 million, respectively. For the nine months ended September 30, 2007, and 2006, there was no revenue from discontinued operations and pre-tax income was $6 million and $117 million, respectively.

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

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

This MD&A contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Edison International’s current expectations and projections about future events based on Edison International’s knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by Edison International that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words “expects,” “believes,” “anticipates,” “estimates,” “projects,” “intends,” “plans,” “probable,” “may,” “will,” “could,” “would,” “should,” and variations of such words and similar expressions, or discussions of strategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ, or that otherwise could impact Edison International or its subsidiaries, include, but are not limited to:

Additional information about risks and uncertainties, including more detail about the factors described above, are discussed throughout this MD&A and in the “Risk Factors” section included in Part I, Item 1A of Edison International’s 2006 Annual Report on Form 10-K. Readers are urged to read this entire report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect Edison International’s business. Forward-looking statements speak only as of the date they are made and Edison International is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International with the Securities & Exchange Commission.

Edison International is engaged in the business of holding, for investment, the common stock of its subsidiaries. Edison International’s principal operating subsidiaries are SCE, a rate-regulated electric utility, and EMG. EMG is the holding company for its principal wholly owned subsidiaries, EME, which is engaged in the business of developing, acquiring, owning, or leasing, operating and selling energy and capacity from independent power production facilities, and Edison Capital, a provider of capital and financial services.

In this MD&A, except when stated to the contrary, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to Edison International (parent) or parent company mean Edison International or on a stand-alone basis, not consolidated with its subsidiaries.

This MD&A is presented in 8 major sections. The company-by-company discussion of SCE, EMG, and Edison International (parent) includes discussions of liquidity, market risk exposures, and other matters (as relevant to each principal business segment). The remaining sections discuss Edison International on a consolidated basis. The consolidated sections should be read in conjunction with the discussion of each company’s section.

The following section provides a summary of current developments related to Edison International’s principal business segments. This section is intended to be a summary of those current developments that management believes are of most importance since year-end December 31, 2006. This section is not intended to be an all-inclusive list of all current developments related to each principal business segment and should be read together with all sections of this MD&A.

On October 1, 2007, a Presiding Officer’s Decision was released regarding the investigation into SCE’s incentives claimed under a CPUC-approved PBR mechanism that allowed SCE to earn rewards or penalties for the period of 1997 – 2003 based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability. The Presiding Officer’s Decision orders SCE to refund incentives already collected and forgo incentives claimed but not collected in the total amount of $160 million, plus interest, and pay a penalty of $40 million. Included in the $160 million to be refunded or forgone is $48 million related to customer satisfaction rewards, $35 million related to employee safety rewards, and $77 million related to amounts collected in rates for employee bonuses (“results sharing”) (which is required to be adjusted for escalation). On October 31, 2007, SCE appealed the Presiding Officer’s Decision to the CPUC. See “SCE: Regulatory Matters —Investigations Regarding Performance Incentives Rewards” for further discussion.

On September 20, 2007, the CPUC issued a decision that adopted an Energy Efficiency Risk/Reward Incentive mechanism covering two three year periods (2006 – 2008 and 2009 – 2011). The mechanism allows for both incentives and economic penalties based on SCE’s performance toward meeting CPUC goals for energy efficiency. The intent of the mechanism is to elevate the importance of customer energy efficiency programs by allowing utility shareholders to participate in the benefits produced by such programs, ensuring that energy efficiency is viewed as a core part of the utilities’ operations. Both incentives and economic penalties for each three year period are capped at $200 million. Assuming SCE achieves its energy efficiency and net benefit goals of approximately $1.2 billion, the three-year earnings opportunity would be approximately $146 million pre-tax, a portion of which is expected to be collected through rates beginning in 2009. See “SCE: Regulatory Matters—Energy Efficiency Shareholder Risk/Reward Incentive Mechanism” for further discussion.

On May 8, 2007, SCE filed its 2008 cost of capital application requesting a rate-making capital structure of 43% long-term debt, 9% preferred equity and 48% common equity. In addition, SCE requested a cost of long-term debt of 6.20%, cost of preferred equity of 5.98% and a return on common equity of 11.80%. On September 20, 2007, SCE updated its requested cost of long-term debt to 6.22% and its requested cost of preferred equity to 6.01%. SCE expects a decision on the 2008 cost of capital application by the end of 2007.

On September 19, 2007, the DRA accepted SCE’s modified NOI. SCE expects to file its GRC application in November 2007. A final decision on SCE’s 2009 GRC is expected by December 2008. On July 23, 2007, SCE tendered to the CPUC’s DRA its NOI to file a 2009 GRC application. The NOI indicates that SCE’s GRC application will request a 2009 base rate revenue requirement of $5.19 billion, an increase of approximately $856 million over the projected 2008 authorized base rate revenue requirement. After considering the effects of sales growth and other offsets, SCE’s request would be a $724 million increase over current authorized base rate

revenue. If the CPUC approves these requested increases and allocates them to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 16.2% and 6.2%, respectively. The requested revenue requirement increase is necessary for SCE to build facilities to serve new customers, reinforce its system to accommodate customer load growth, replace aging infrastructure, meet regulatory requirements in generation and electricity procurement, fund increased operations and maintenance costs, and provide for increased costs to recruit, train, and retain employees in light of anticipated retirements. The NOI also identifies that SCE’s application will propose a post-test year ratemaking mechanism which would result in 2010 and 2011 base rate revenue requirement increases, net of sales growth, of $251 million and $285 million, respectively, for the same reasons. SCE will also be requesting in its application that Mountainview be included in utility rate base and its operating costs be recovered through the 2009 GRC revenue requirement rather than the current structure under which SCE recovers Mountainview generating costs through a power purchase agreement. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted.

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

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

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

EME has continued to expand its business development activities in order to grow and diversify its existing portfolio of power projects. Most of the near-term development and investment activity is in wind power, where EME has targeted to have approximately 2,000 MW of wind capacity in service by the end of 2009. At September 30, 2007, EME had 471 MW of wind projects in service and another 523 of wind projects under construction with scheduled completion dates into 2008. At September 30, 2007, EME had a development pipeline of potential wind projects with an estimated installed capacity of approximately 3,000 MW (the development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive negotiation rights). This development pipeline is supported by turbine purchase commitments for

wind projects that would aggregate 1,185 MW. Completion of these projects is dependent upon a number of items which may include, depending on the project’s status, completion of a power sales agreement, permits, an interconnection agreement or other agreements necessary to start construction. Additional projects may from time to time be added to the development pipeline, and there is no assurance that the projects included in the development pipeline currently or added in the future will lead to the successful completion of a wind project. See “EMG: Liquidity—Business Development” for details of activities during the nine-month period ended September 30, 2007.

During 2007, PJM completed capacity auctions under the PJM RPM for periods through May 31, 2010. EME participated in each auction which sold forward significant capacity at prices from $40.80 per MW-day to $191.32 per MW-day. The increase in capacity prices determined through the PJM RPM reflected the auction design to encourage increased capacity resources to meet projected demand. As a result of these auctions, capacity revenue is expected to increase significantly through May 31, 2010 as compared to the amounts realized previously. For further discussion regarding the PJM and recent auctions, see “EMG: Market Risk Exposures—Commodity Price Risk—Capacity Price Risk.”

On July 24, 2007, Midwest Generation and EMMT, along with other power generation companies and utilities, entered into a settlement agreement with the Illinois Attorney General that subsequently resulted in legislation that was signed by the Governor of Illinois. The legislation established a new Illinois Power Agency to manage future power procurement for the Illinois regulated utilities, Commonwealth Edison and Ameren (beginning with the planning year June 1, 2009 through May 31, 2010). The settlement legislation was passed by the Illinois legislature on July 26, 2007, and was signed by the Governor of Illinois on August 28, 2007. As part of the settlement, Midwest Generation has agreed to pay $25 million over three years toward approximately $1 billion in utility customer rate relief and startup costs of the new Illinois Power Agency. Also as part of the settlement, all auction-related complaints filed by the Illinois Attorney General at the FERC, the Illinois Commerce Commission and in the Illinois courts have been dismissed. See “EMG: Other Developments—Settlement with Illinois Attorney General” for further discussion.

On May 7, 2007, EME completed a private offering of $1.2 billion of its 7.00% senior notes due 2017, $800 million of its 7.20% senior notes due 2019 and $700 million of its 7.625% senior notes due 2027. EME will pay interest on the senior notes on May 15 and November 15 of each year, beginning on November 15, 2007. On October 22, 2007, EME commenced an exchange offer to exchange the senior notes for an equal principal amount of senior notes which have been registered under the Securities Act. The net proceeds were used, together with cash on hand, to:

The refinancing activities improved EMG’s overall liquidity, operating flexibility and ability to capitalize on growth opportunities. EMG recorded a total pre-tax loss on early extinguishment of debt of approximately $241 million (approximately $148 million after tax) for the nine-month period ended September 30, 2007.

As of September 30, 2007, SCE had cash and equivalents of $115 million ($104 million of which was held by SCE’s consolidated VIEs). As of September 30, 2007, long-term debt, including current maturities of long-term debt, was $5.3 billion. On February 23, 2007, SCE amended its credit facility, increasing the amount of borrowing capacity to $2.5 billion, extending the maturity to February 2012 and removing the first mortgage bond security pledge. As a result of removing the first mortgage bond security, the credit facility’s pricing changed to an unsecured basis per the terms of the credit facility agreement. At September 30, 2007, the credit facility supported $200 million in letters of credit, leaving $2.3 billion available for liquidity purposes.

SCE’s estimated cash outflows during the 12-month period following September 30, 2007 are expected to consist of:

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

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

As discussed under the heading “SCE: Liquidity—Capital Expenditures” in the year-ended 2006 MD&A, SCE is experiencing significant growth in actual and planned capital expenditures to replace and expand and construct its distribution and transmission infrastructure, and to construct and replace major components of generation assets. SCE’s 2007 through 2011 capital investment plan includes total capital spending of up to $17.3 billion. During the nine-month period ended September 30, 2007, SCE spent $1.54 billion in capital expenditures related to its 2007 capital plan.

On September 6, 2007, S&P raised SCE’s credit rating for long-term senior secured debt to A from BBB+. SCE cannot provide assurance that its current credit ratings will remain in effect for any given period of time or that one or more of these ratings will not be changed. These credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

The CPUC regulates SCE’s capital structure and limits the dividends it may pay Edison International (see “Edison International (Parent): Liquidity” for further discussion). In SCE’s most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE determines compliance with this capital structure based on a 13-month weighted-average calculation. At September 30, 2007, SCE’s 13-month weighted-average common equity component of total capitalization was 50.18%. At September 30, 2007, SCE had the capacity to pay $260 million in additional dividends based on the 13-month weighted-average method. However, based on recorded September 30, 2007 balances, SCE’s common equity to total capitalization ratio (as adjusted for rate-making purposes) was 51.58%. SCE had the capacity to pay $427 million of additional dividends to Edison International based on September 30, 2007 recorded balances.

SCE has a debt covenant in its credit facility that requires a debt to total capitalization ratio of less than or equal to 0.65 to 1 to be met. At September 30, 2007, SCE’s debt to total capitalization ratio was 0.43 to 1.

SCE has entered into certain margining agreements for power and gas trading activities in support of its procurement plan as approved by the CPUC. SCE’s margin deposit requirements under these agreements can vary depending upon the level of unsecured credit extended by counterparties and brokers, changes in market prices relative to contractual commitments, and other factors. At September 30, 2007, SCE had a net deposit of $195 million (consisting of $35 million in cash and reflected in “Margin and collateral deposits” on the consolidated balance sheet and $160 million in letters of credit) with counterparties. In addition, SCE has deposited $51 million (consisting of $11 million in cash and reflected in “Margin and collateral deposits” on the consolidated balance sheet and $40 million in letters of credit) with other brokers. Cash deposits with brokers and counterparties earn interest at various rates.

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

SCE is concerned about high customer rates, which were a contributing factor that led to the deregulation of the electric services industry during the mid-1990s. On January 1, 2007, SCE’s bundled service system average rate

was 14.5¢ per-kWh (including 3.1¢ per-kWh related to CDWR which is not recognized as revenue by SCE). On February 14, 2007, SCE’s system average rate decreased to 13.9¢-per-kWh (including 3.0¢ per-kWh related to CDWR) mainly as the result of projected lower natural gas prices in 2007, as well as the refund of overcollections in the ERRA balancing account that occurred in 2006 from lower than expected natural gas prices and higher than expected summer 2006 kWh sales (see “—Energy Resource Recovery Account Proceedings” below). In addition, the rate change incorporates the redesign of SCE’s tiered rate structure resulting in a decrease of rates in the higher tiers for residential customers and collection of the residential rate increase deferral discussed in the year-ended 2006 MD&A under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates.”

On August 1, 2007, SCE filed its 2008 ERRA forecast application in which it forecasts an ERRA revenue requirement of $4.3 billion, an increase of $515 million over SCE’s adopted 2007 ERRA revenue requirement. In addition, SCE requested to consolidate other rate changes authorized by the CPUC with this ERRA revenue requirement increase effective on or soon after January 1, 2008. SCE estimated an increase of $528 million in its total system 2008 consolidated revenue requirement when combining the ERRA revenue requirement increase with all other estimated CPUC-authorized revenue requirement changes. After taking estimated 2008 sales growth into account, SCE estimates a total system revenue increase of $447 million. Implementation of the increased consolidated revenue requirement, as requested, would increase the bundled service system average rate from the current system average rate of 13.9¢ per-kWh (including 3.0¢ per- kWh related to CDWR) to 14.4¢ per-kWh (including 3.1¢ per-kWh related to CDWR), an increase of 3.6%. SCE will revise its requested 2008 ERRA revenue requirement November 2007. Based on SCE’s current ERRA balancing account overcollection, and anticipated lower 2008 power and gas prices, SCE expects the 2008 ERRA revenue requirement and bundled system average rate to decrease from its original forecast of 14.4¢ per-kWh filed in August 2007.

On September 20, 2007, the CPUC issued a decision that adopted an Energy Efficiency Risk/Reward Incentive mechanism. The CPUC will review the operation of the mechanism over two three year program periods (2006 – 2008 and 2009 – 2011) to determine if any modifications to the mechanism are warranted for the 2012 – 2014 program period. SCE has the opportunity to earn an incentive of 9% of the value of the total energy efficiency savings if it achieves between 85% and 100% of its energy efficiency goals for the cumulative three year period and can earn 12% of the value of the energy efficiency savings if 100% or greater of its goals are achieved. Economic penalties would be imposed in the event the utility achieves 65% or less of its goals. The mechanism also establishes a deadband between 65% and 85% of energy efficiency goals, where no economic penalty or incentive would be earned. The mechanism allows for collection of 70% of the first two years (2006 – 2007) progress in customer rates, beginning in 2009; 70% of the next year’s (2008) progress in 2010 and collection of a final true-up payment for the remaining 30%, as adjusted for actual performance in 2011. SCE is scheduled to file advice filings in September of each year requesting recovery of the progress payments in accordance with the mechanism. SCE expects it will recognize earnings in the amount of the progress payments upon CPUC acceptance of its filing, expected in the fourth quarter of each year. On October 31, 2007, SCE and the other California utilities filed a joint petition for modification which would allow the utilities to retain the first and second progress payments as long as the utilities meet a minimum of 65% of the anticipated goals. If the utilities fall below the 65% level, the progress payments would need to be refunded and economic penalties would be incurred. In the event SCE reaches 100% of its goals for the 2006 – 2008 period, the approximate incentive would be $146 million pre-tax in total for the three year period. SCE currently estimates it will meet 100% of its energy efficiency goals. In the event SCE reaches 65% or less of its goals for the 2006 – 2008 period, the approximate economic penalty could range between $58 million to $200 million for the three year period, depending on SCE’s performance against its energy efficiency goals.

On May 18, 2007, SCE filed a petition seeking incentives for three of its largest proposed transmission projects: Devers-Palo Verde II (“DPV2”) (a high voltage (500 kV) transmission line from Devers substation near Palm Springs, California to a new substation near Palo Verde, west of Phoenix), the Tehachapi Transmission Project (“Tehachapi”) (an eleven transmission line segments and associated substations project to interconnect renewable generation projects near the Tehachapi and Big Creek area), and the Rancho Vista Substation project (“Rancho Vista”) (a proposed new 500kV substation in the City of Rancho Cucamonga). In its petition, SCE requested a higher return on equity on SCE’s entire transmission rate base in SCE’s next FERC transmission rate case and an additional increase for these three projects upon approval of SCE’s incentive filing. In addition, the petition requests to include in rate base 100% of prudently-incurred capital expenditures during the construction of all three projects and 100% recovery of prudently-incurred abandoned plant costs for DPV2 and Tehachapi, if either or both of these projects are cancelled due to factors beyond SCE’s control. A FERC ruling on the petition is likely to be issued before year-end 2007.

The Tehachapi and Rancho Vista projects are proceeding as anticipated. However, despite SCE having obtained approvals for the DPV2 project from the CPUC and other Arizona governmental agencies, by a decision dated June 6, 2007 the Arizona Corporation Commission (ACC) denied approval of the DPV2 project. SCE’s application for rehearing and reconsideration was subsequently denied due to inaction by the ACC. SCE filed an appeal of the ACC’s decision with the Maricopa County Superior Court on August 31, 2007 and agreed to a stay of the appeal until March 2008 in order to allow it to explore potential options with the Arizona stakeholders, including the ACC. SCE continues to evaluate its options, which include filing a new application with the ACC and building the project in various phases. As of September 30, 2007, SCE has spent approximately $29 million on this project. SCE expects to fully recover its costs from this project, but cannot predict the outcome of regulatory proceedings.

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings” in the year-ended 2006 MD&A, the ERRA is the balancing account mechanism to track and ensure recovery of SCE’s fuel and power procurement-related costs. At December 31, 2006, the ERRA was overcollected by $526 million, which was 13.2% of SCE’s prior year’s generation revenue. On January 25, 2007, the CPUC approved SCE’s request to reduce the 2007 ERRA revenue requirement by $630 million. The CPUC also authorized SCE to consolidate the decreased ERRA revenue requirement with the authorized revenue requirement changes in other SCE proceedings resulting in lower rate levels implemented in February 2007. See “—Impact of Regulatory Matters on Customer Rates” above for further discussion. At September 30, 2007, the ERRA was overcollected by $557 million. SCE had anticipated this overcollection to decrease during 2007, based on the reduced ERRA revenue requirement approved by the CPUC on January 25, 2007. However, due to the impact of lower gas prices, as compared to forecast, and higher revenue resulting from warmer weather, SCE’s ERRA overcollection balance began to increase in August 2007. SCE will notify the CPUC that the 2007 ERRA overcollection has exceeded 5% of SCE’s generation revenue from the prior year and will propose to include the refund of the ERRA overcollection in the planned rate change on January 1, 2008 or soon thereafter. The 2008 ERRA revenue requirement will be updated in November 2007 to reflect the latest ERRA overcollection balance as discussed above in “—Impact of Regulatory Matters on Customer Rates.”

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—ISO Disputed Charges” in the year-ended 2006 MD&A, on April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. On March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support

and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. On May 25, 2007, the FERC issued a procedural order granting the rehearing application for the 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 provide assurance as to the final outcome of the rehearing. If a subsequent regulatory decision changes the allocation of responsibility for these charges, and SCE is required to pay these charges as a transmission owner, SCE may seek recovery in its reliability service rates. SCE cannot provide any assurance that recovery of these charges in its reliability service rates would be permitted.

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Peaker Plant Generation Projects” in the year-ended 2006 MD&A, SCE pursued construction of five combustion turbine peaker plants. In August 2007, four of these peaker plants were placed online and were dispatched in August to help meet peak customer demands. SCE continues to pursue the construction of the fifth project, but the required construction permit has been denied by the City of Oxnard. SCE believes the permit denial to be without merit and has appealed this denial to the Coastal Commission and expects a decision in the first quarter of 2008. However, SCE cannot predict the outcome of the proceeding nor estimate the impact of a delayed permit issuance on the project’s construction schedule. SCE believes that the peaker plants will help meet electric reliability needs, notwithstanding the delay encountered by the fifth project. SCE has revised its budget for all five projects from its original estimate of $250 million to approximately $300 million. As of September 30, 2007, SCE has spent or firmly committed approximately $280 million in costs for all five projects. SCE expects to fully recover its costs from these projects, but cannot predict the outcome of regulatory proceedings.

pay refunds and to release to governmental suppliers the amounts that had been withheld from, as well as collateral posted, from such suppliers for power delivered during the energy crisis. In its order, the FERC also expressly recognized that civil lawsuits against the governmental suppliers could provide an alternative refund remedy for SCE and the other California utilities. It also left open the possibility that a court with jurisdiction over the matter could order the ISO or PX to retain collateral. SCE cannot predict at this time the impact of the FERC’s order or whether SCE may be able to recover any additional refunds from governmental power sellers as a result of the pending lawsuits.

In November 2005, SCE and other parties entered into a settlement agreement with Enron Corporation and a number of its affiliates, most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In 2006, SCE received distributions of approximately $55 million on its allowed bankruptcy claim. In April 2007, SCE received and recorded an additional distribution on its allowed bankruptcy claim of approximately $12 million and 55,465 shares of Portland General Electric Company stock, with an aggregate value of less than $2 million. In October 2007, SCE received an additional distribution on its allowed bankruptcy claim of approximately $10 million. Additional distributions are expected but SCE cannot currently predict the amount or timing of such distributions.

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.

On June 15, 2006, the CPUC instituted a formal investigation to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer satisfaction, employee safety and system reliability portions of PBR. In June 2006, the CPSD of the CPUC issued its report regarding SCE’s PBR program, recommending that the CPUC impose various refunds and penalties on SCE. Subsequently, in September 2006, the CPSD and other intervenors, such as the CPUC’s DRA and The Utility Reform Network, filed testimony on these matters recommending various refunds and penalties be imposed on SCE. In their testimony, the various parties made refund and penalty recommendations that range up to the following amounts: refund or forgo $48 million in rewards for customer satisfaction, impose $70 million penalties for customer satisfaction, refund or forgo $35 million in rewards for employee safety, impose $35 million penalties for employee safety, impose $102 million in statutory penalties, refund $84 million of results sharing, refund $4 million of miscellaneous survey expenses, and require $10 million of new employee safety programs. These recommendations total up to $388 million. On October 16, 2006, SCE filed testimony opposing the various refund and penalty recommendations of the CPSD and other intervenors.

satisfaction rewards, $35 million related to employee safety rewards, and $77 million related to results sharing. The decision requires that the proposed results sharing refund of $77 million (based on year 2000 data) be adjusted for attrition and escalation which increases the result sharing refund to $88 million. After the result sharing adjustment is made, the total amount SCE would be required to refund increases to $136 million, before interest. Interest to date, based on amounts collected for customer satisfaction, safety incentives and results sharing, including escalation and attrition adjustments, would add an additional $26 million to this amount. On October 31, 2007, SCE appealed the POD to the CPUC.

SCE cannot predict the outcome of the appeal. Based on SCE’s proposed refunds, the combined recommendations of the CPSD and other intervenors, as well as the POD, the potential refunds and penalties could range from $52 million up to $388 million. SCE has recorded an accrual at the lower end of this range of potential loss and is accruing interest (approximately $15 million as of September 30, 2007) on collected amounts that SCE has proposed to refund to customers.

In early 2006, the ISO began a program to redesign and upgrade the wholesale energy market across ISO’s controlled grid, known as the MRTU. The programs under the MRTU initiative are designed to implement market improvements to assure grid reliability, more efficient and cost-effective use of resources, and to create technology upgrades that would strengthen the entire ISO computer system. The redesigned California energy

market under the MRTU is expected to include the following new features, among others, which are not part of the current ISO real-time only market:

The MRTU is scheduled for implementation on March 31, 2008. Power will be scheduled on a nodal basis, rather than the current zonal system, which will aid in grid reliability and congestion management. Furthermore, the MRTU will incorporate the CPUC’s resource adequacy requirements to ensure that there are adequate energy resources in critical areas. The MRTU will not affect how costs are recovered through rates. SCE continues to work with the ISO to develop the MRTU.

SCE’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. SCE uses derivative financial instruments, as appropriate, to manage its market risks.

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

SCE has an active hedging program in place to minimize ratepayer exposure to spot-market price spikes; however, to the extent that SCE does not mitigate the exposure to commodity price risk, the unhedged portion is subject to the risks and benefits of spot-market price movements, which are ultimately passed-through to ratepayers.

To mitigate SCE’s exposure to spot-market prices, SCE enters into energy options, tolling arrangements, and forward physical contracts. In the first quarter of 2007 SCE secured FTRs through the annual ISO auction. These FTRs provide SCE with scheduling priority in certain transmission grid congestion areas in the day-ahead market and qualify as derivative instruments. SCE also enters into contracts for power and gas options, as well as swaps and futures, in order to mitigate its exposure to increases in natural gas and electricity pricing. These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans.

SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale. Certain derivative instruments do not meet the normal purchases and sales exception because demand variations and CPUC mandated resource adequacy requirements may result in physical delivery of excess energy that may not be in quantities that are expected to be used over a reasonable period in the normal course of business and may then be resold into the market. In addition, certain contracts do not meet the definition of clearly and closely related under SFAS No. 133 since pricing for certain renewable contracts is based on an unrelated commodity. The derivative instrument fair values are marked to market at each reporting period. Any fair value changes for recorded derivatives are recorded in purchased-power expense and offset through the provision for regulatory adjustment clauses – net; therefore, fair value changes do not affect earnings. Hedge accounting is not used for these transactions due to this regulatory accounting treatment.

In September 2007, the ISO allocated CRRs to SCE which will entitle SCE to receive (or pay) the value of transmission congestion at specific locations. These rights will act as an economic hedge against transmission congestion costs in the MRTU environment which is expected to be operational March 31, 2008. The CRRs meet the definition of a derivative under FAS 133. There is insufficient evidence of a measurement date, and no quoted market prices given that MRTU is not yet implemented. As a result, as of September 30, 2007, the CRRs had no value.

SCE has not elected to use hedge accounting for the CRRs. Future fair value changes will be recorded in purchased-power expense and offset through the provision for regulatory adjustments clauses as the CPUC

allows these costs to be recovered from or refunded to customers through a regulatory balancing account mechanism. As a result, fair value changes are not expected to affect earnings.

The following table summarizes the fair values of outstanding derivative financial instruments used at SCE to mitigate its exposure to spot market prices:

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

In July 2007, SCE entered into interest-lock derivative instruments to economically hedge the anticipated future issuance of long-term debt. SCE expects to recover any fair value changes associated with the interest-lock derivative instruments through regulatory mechanisms and has therefore elected not to use hedge accounting. Realized and unrealized gains and losses do not affect current earnings. Realized gains and losses are amortized to interest expense over the life of the debt. At September 30, 2007, unrealized losses were $7 million and are reflected as derivative liabilities on the consolidated balance sheets.

The increase for the nine months ended September 30, 2007 in net unrealized gains / losses on economic hedging activities primarily resulted from changes in SCE’s gas hedge portfolio mix as well as the movements in the natural gas futures market. Due to expected recovery through regulatory mechanisms unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings.

At September 30, 2007, EMG and its subsidiaries had cash and cash equivalents and short-term investments of $1.52 billion, EMG had a total of $1.0 billion of available borrowing capacity under its credit facilities. EMG’s consolidated debt at September 30, 2007 was $3.96 billion. In addition, EME’s subsidiaries had $4.0 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 27 years.

During the second quarter of 2007, EME amended its existing $500 million secured credit facility, increasing the total borrowings available thereunder to $600 million, and Midwest Generation amended and restated its existing $500 million senior secured working capital facility. The changes to the senior secured working capital facility included a reduction in the interest rate, a longer maturity date, and fewer restrictive covenants. Midwest Generation intends to use its secured working capital facility to provide credit support for its hedging activities and for general working capital purposes. Midwest Generation may also support its hedging activities by granting first or second priority liens to eligible hedge counterparties.

EME has undertaken a number of activities in 2007 with respect to wind projects, including the following:

At September 30, 2007, the estimated capital expenditures through 2009 by EME’s subsidiaries related to existing projects, corporate activities and turbine commitments were as follows:

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls and dust collection/mitigation systems, a spare main power transformer, railroad interconnection and an expansion of a coal cleaning plant refuse site. Environmental expenditures relate to environmental projects such as mercury emission monitoring and control and SCR performance improvements at the Homer City facilities and various projects at the Illinois plants to achieve specified emissions reductions such as installation of mercury controls. EME plans to finance these expenditures with financings, cash on hand or cash generated from operations. See further discussion regarding these and possible additional capital expenditures, including environmental control equipment at the Homer City facilities, under “Edison International: Management’s Overview” and “Other Developments—Environmental Matters—Air Quality Standards,” and “—Clean Air Act—Illinois,” and “—Mercury Regulation” in the year-ended 2006 MD&A.

EME expects to make substantial investments in new projects during the next several years. At September 30, 2007, EME had committed to purchase turbines (as reflected in the above table of capital expenditures) for wind projects that aggregate 1,185 MW. The turbine commitments generally represent approximately two-thirds of the

total capital costs of EME’s wind projects. As of September 30, 2007, EME had a development pipeline of potential wind projects with an installed capacity of approximately 3,000 MW (the development pipeline represents potential projects which EME either owns the project rights or has exclusive negotiation rights). Completion of these projects is dependent upon a number of items which may include, depending on the project’s status, completion of a power sales agreement, permits, an interconnection agreement or other agreements necessary to start construction. Additional projects may from time to time be added to the development pipeline, and there is no assurance that the projects included in the development pipeline currently or added in the future will lead to the successful completion of a wind project.

Credit ratings for EMG’s direct and indirect subsidiaries at September 30, 2007, were as follows:

EMG cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EMG notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

EMG does not have any “rating triggers” contained in subsidiary financings that would result in it being required to make equity contributions or provide additional financial support to its subsidiaries.

The Homer City sale-leaseback documents restrict EME Homer City’s ability to enter into trading activities, as defined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from S&P or Moody’s or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME’s internal credit scoring procedures. These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City facilities through EMMT, which has a below investment grade credit rating, and EME Homer City is not rated. Therefore, in order for EME to continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to permit EME Homer City to sell directly into the market or through EMMT; or (2) EMMT must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participant that will allow EME Homer City to enter into such sales, under specified conditions, through December 31, 2008. EME Homer City continues to be in compliance with the terms of the consent. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See “EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities.”

In connection with entering into contracts in support of EME’s hedging and energy trading activities (including forward contracts, transmission contracts and futures contracts), EME’s subsidiary, EMMT, has entered into agreements to mitigate the risk of nonperformance. EME has entered into guarantees in support of EMMT’s hedging and trading activities; however, because the credit ratings of EMMT and EME are below investment

grade, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to accounts payable and unrealized losses in connection with these hedging and trading activities. At September 30, 2007, EMMT had deposited $51 million in cash with brokers in margin accounts in support of futures contracts and had deposited $58 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $30 million in support of commodity contracts at September 30, 2007.

Future cash collateral requirements may be higher than the margin and collateral requirements at September 30, 2007, if wholesale energy prices increase or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of September 30, 2007 could increase by approximately $390 million over the remaining life of the contracts using a 95% confidence level.

Midwest Generation has cash on hand and a $500 million working capital facility to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois plants. At September 30, 2007, Midwest Generation had available $497 million of borrowing capacity under this credit facility. As of September 30, 2007, Midwest Generation had $28 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and $508 million of borrowing capacity available under a $600 million working capital facility to provide credit support to subsidiaries.

EME and Edison Capital are included in the consolidated federal and combined state income tax returns of Edison International and are eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The rights of EME and Edison Capital to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME and Edison Capital in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EMG’s subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME and Edison Capital receive tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize EME’s or Edison Capital’s consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, each of EME and Edison Capital is obligated during periods it generates taxable income, to make payments under the tax-allocation agreements. EME received tax-allocation payments from Edison International of $70 million and $159 million during the third quarters of 2007 and 2006, respectively. EME made cumulative tax-allocation payments, net of third quarter receipts, to Edison International of $86 million and $3 million during the first nine months of 2007 and 2006, respectively. Edison Capital made tax-allocation payments to Edison International of $48 million during the third quarter of 2007 and received net tax allocation payments of $66 million, $32 million, and $130 million during the third quarter of 2006, and the first nine months of 2007 and 2006, respectively. MEHC (parent) received tax-allocation payments from Edison International of $33 million, and $14 million for the third quarters of 2007 and 2006, respectively, and $52 million, and $30 million for the first nine months of 2007 and 2006, respectively.

Each of EMG’s direct or indirect subsidiaries is organized as a legal entity separate and apart from EMG and its other subsidiaries. Assets of EMG’s subsidiaries are not available to satisfy the obligations of any of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EMG or to its subsidiary holding companies.

Set forth below are key ratios of EME’s principal subsidiaries required by financing arrangements at September 30, 2007 or for the twelve months ended September 30, 2007:

For a more detailed description of the covenants binding EME’s principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to “EMG: Liquidity—MEHC’s Dividend Restrictions in Major Financings” in the year-ended 2006 MD&A.

Edison Capital’s ability to make dividend payments is currently restricted by covenants in its financial instruments, which require Edison Capital, through a wholly owned subsidiary, to maintain a specified minimum net worth of $200 million. Edison Capital satisfied this minimum net worth requirement as of September 30, 2007.

In October 2006, EMMT was advised by the enforcement staff at the FERC that it is prepared to recommend that the FERC initiate a formal investigatory proceeding and seek monetary sanctions against EMMT for alleged violation of the Energy Policy Act of 2005 and the FERC’s rules regarding market behavior, all with respect to certain bidding practices previously employed by EMMT. EMMT is engaged in discussions with the staff to explore the possibility of resolution of this matter. Discussions to date have been constructive and may lead to a settlement agreement acceptable to both parties. Should these discussions not result in a settlement and a formal proceeding commenced, EMMT will be entitled to contest any alleged violations before the FERC and an appropriate court. EME believes that EMMT has complied with all applicable laws and regulations and intends to contest vigorously any allegation of violation.

On July 24, 2007, Midwest Generation and EMMT, along with other power generation companies and utilities, entered into a settlement agreement with the Illinois Attorney General. The settlement was subject to the passage of legislation which will, among other things, establish a new Illinois Power Agency to manage future power procurement for the Illinois regulated utilities, Commonwealth Edison and Ameren (beginning with the planning year June 1, 2009 through May 31, 2010). The settlement legislation was passed by the Illinois legislature on July 26, 2007, and was signed by the Governor of Illinois on August 28, 2007.

of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the Clean Air Act, including alleged requirements to obtain a construction permit and to install Best Available Control Technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the Clean Air Act. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. Midwest Generation, the US EPA, and the DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. As a result, Midwest Generation is investigating the claims made by the US EPA in the NOV and has identified several defenses which it will raise if the government files suit. At this early stage in the process, Midwest Generation cannot predict the effect this matter may have on its facilities, its results of operations or financial position.

By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Midwest Generation and Commonwealth Edison have executed a standstill arrangement for the indemnity claims and a joint defense protocol. Midwest Generation and Commonwealth Edison are cooperating with one another in responding to the NOV.

On December 22, 2006, the FERC issued an order conditionally approving the RPM settlement subject to PJM making certain compliance filings. The compliance filings were made by PJM on January 22, 2007 and February 20, 2007, and accepted by the FERC on June 25, 2007 and July 11, 2007, respectively. On June 1, 2007, PJM implemented marginal losses for transmission for its competitive wholesale electric market. For further discussion regarding the RPM and recent auctions, see “EMG: Market Risk Exposures—Commodity Price Risk—Capacity Price Risk.” EME is still evaluating the impact that marginal loss pricing in PJM will have on its results of operations, but continues to believe that it may reduce locational marginal prices for some of its units relative to the locational marginal prices for the benchmark locations of Western Hub and Northern Illinois Hub.

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994 to 1996 and 1997 to 1999 tax years, respectively. Among the issues raised were items related to Edison Capital. See “Other Developments—Federal and State Income Taxes” for further discussion of these matters.

EMG’s primary market risk exposures are associated with the sale of electricity and capacity from and the procurement of fuel for EME’s merchant power plants. These market risks arise from fluctuations in electricity, capacity and fuel prices, emission allowances, and transmission rights. Additionally, EME’s financial results can

be affected by fluctuations in interest rates. EME manages these risks in part by using derivative financial instruments in accordance with established policies and procedures.

EME’s revenue and results of operations of its merchant power plants will depend upon prevailing market prices for capacity, energy, ancillary services, emission allowances or credits, coal, natural gas and fuel oil, and associated transportation costs in the market areas where EME’s merchant plants are located. Among the factors that influence the price of energy, capacity and ancillary services in these markets are:

A discussion of commodity price risk for the Illinois plants and the Homer City facilities is set forth below.

EME’s merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored by a risk management committee to ensure compliance with EME’s risk management policies. Policies are in place which define risk management processes, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by EME’s risk management committee. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

In addition to prevailing market prices, EME’s ability to derive profits from the sale of electricity will be affected by the cost of production, including costs incurred to comply with environmental regulations. The costs of production of the units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the units is expected to vary.

EME uses “value at risk” to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois plants, its Homer City facilities, and its trading positions. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible loss over a given time interval, under normal market conditions, at a given confidence

level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss limits and counterparty credit exposure limits.

To reduce its exposure to market risk, EME hedges a portion of its merchant portfolio risk through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its merchant portfolio, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented through:

The extent to which EME enters into contracts to hedge its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared to assuming the risk associated with fluctuating spot market sales. Second, EME’s ability to enter into hedging transactions depends upon its and Midwest Generation’s credit capacity and upon the forward sales markets having sufficient liquidity to enable EME to identify appropriate counterparties for hedging transactions.

In the case of hedging transactions related to the generation and capacity of the Illinois plants, Midwest Generation is permitted to use its working capital facility and cash on hand to provide credit support for these hedging transactions entered into by EMMT under an energy services agreement between Midwest Generation and EMMT. Utilization of this credit facility in support of hedging transactions provides additional liquidity support for implementation of EME’s contracting strategy for the Illinois plants. In addition, Midwest Generation is permitted to grant liens on its property in support of hedging transactions associated with the Illinois plants. In the case of hedging transactions related to the generation and capacity of the Homer City facilities, credit support is provided by EME pursuant to intercompany arrangements between it and EMMT. See “—Credit Risk” below.

All the energy and capacity from the Illinois plants is sold under terms, including price and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. As discussed further below, power generated at the Illinois plants is generally sold into the PJM market.

Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to the generation of the Illinois plants are generally entered into at the Northern Illinois Hub in PJM, and may also be entered into at other trading hubs, including the AEP/Dayton Hub in PJM and the Cinergy Hub in the MISO. These trading hubs have been the most liquid locations for hedging purposes. However, hedging transactions which settle at points other than the Northern Illinois Hub are subject to the possibility of basis risk. See “—Basis Risk” below for further discussion.

PJM has a short-term market, which establishes an hourly clearing price. The Illinois plants are situated in the PJM control area and are physically connected to high-voltage transmission lines serving this market.

The following table depicts the average historical market prices for energy per megawatt-hour during the first nine months of 2007 and 2006.

Forward market prices at the Northern Illinois Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth, and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the Illinois plants into these markets may vary materially from the forward market prices set forth in the table below.

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at September 30, 2007:

The following table summarizes Midwest Generation’s hedge position (primarily based on prices at the Northern Illinois Hub) at September 30, 2007:

All the energy and capacity from the Homer City facilities is sold under terms, including price and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Electric power generated at the Homer City facilities is generally sold into the PJM market. PJM has a short-term market, which establishes an hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and NYISO markets.

The following table depicts the average historical market prices for energy per megawatt-hour at the Homer City busbar and in PJM West Hub (EME Homer City’s primary trading hub) during the first nine months of 2007 and 2006:

Forward market prices at the PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the Homer City facilities into these markets may vary materially from the forward market prices set forth in the table below.

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at September 30, 2007:

The following table summarizes EME Homer City’s hedge position at September 30, 2007:

The average price/MWh for EME Homer City’s hedge position is based on PJM West Hub. Energy prices at the Homer City busbar have been lower than energy prices at the PJM West Hub. See “—Basis Risk” below for a discussion of the difference.

On June 1, 2007, PJM implemented the RPM for capacity. The purpose of the RPM is to provide a long-term pricing signal for capacity resources. The RPM allows PJM to satisfy the region’s need for generation capacity, which is then allocated among the load-serving entities through a locational reliability charge.

The first RPM auction took place in April 2007 and resulted in a fixed price for Midwest Generation and EME Homer City’s capacity sold into the auction (included in PJM as “rest of market” location) of $40.80/MW per day for the period from June 1, 2007 through May 31, 2008. The second auction took place in July 2007 and resulted in a fixed price for Midwest Generation and EME Homer City’s capacity sold into the auction of $111.92/MW per day for the period from June 1, 2008 through May 31, 2009. In October 2007, the third auction took place for the period from June 1, 2009 through May 31, 2010 and resulted in a fixed price for Midwest Generation of $102.04/MW-day. EME Homer City was segregated out of the “rest of market” location in PJM into MAAC+APS for a clearing price of $191.32/MW-day. EMMT sold net 4,614 MW of capacity from the Illinois plants and net 1,670 MW of capacity from the Homer City facilities. A subsequent auction will be conducted in January 2008 to auction capacity for the period from June 1, 2010 through May 31, 2011.

Midwest Generation entered into hedge transactions in advance of the RPM auctions with counterparties that are settled through PJM. In October 2007, Midwest Generation sold 715 MW of capacity at a fixed price of $71.46/MW per day for the period from June 1, 2009 through May 31, 2010. In addition, the load service requirements contracts entered into by Midwest Generation with Commonwealth Edison include energy, capacity and ancillary services (sometimes referred to as a “bundled product”). Under PJM’s business rules, Midwest Generation sells all of its available capacity (unit capacity less forced outages) into the RPM and is subject to a locational reliability charge for the load under these contracts. This means that the locational reliability charge generally offsets the related amounts sold in the RPM, which Midwest Generation presents net in the table below.

Prior to the RPM auctions for the relevant delivery periods, EME Homer City sold a portion of its capacity to an unrelated third party for the delivery periods from June 1, 2007 through May 31, 2008 and June 1, 2008 through May 31, 2009. EME Homer City is not receiving the RPM auction clearing price for this previously sold capacity. The price EME Homer City is receiving for these capacity sales is a function of NYISO capacity clearing prices resulting from separate NYISO capacity auctions.

The following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at September 30, 2007:

Revenue from the sale of capacity from Midwest Generation and EME Homer City beyond the periods set forth above will depend upon the amount of capacity available and future market prices either in PJM or nearby markets if EME has an opportunity to capture a higher value associated with those markets. Under PJM’s RPM system, the market price for capacity is generally determined by aggregate market-based supply conditions and an administratively set aggregate demand curve. Among the factors influencing the supply of capacity in any particular market are plant forced outage rates, plant closings, plant delistings (due to plants being removed as capacity resources and/or to export capacity to other markets), capacity imports from other markets, and new entry.

Sales made from the Illinois plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices or day-ahead prices, as the case may be, at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at the individual plant busbars does not exist. A liquid market does exist for a settlement point at the PJM West Hub in the case of the Homer City facilities and for a settlement point at the Northern Illinois Hub in the case of the Illinois plants. EME’s hedging activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. EME’s revenue with respect to such forward contracts include:

Under PJM’s market design, locational marginal pricing, which establishes market prices at specific locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and

losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by transmission constraints. Effective June 1, 2007, PJM implemented marginal losses which adjusts the algorithm that calculates locational marginal prices to include a component for marginal transmission losses in addition to the component included for congestion. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as “basis risk.” During the nine months ended September 30, 2007, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 15%, compared to 12% during the nine months ended September 30, 2006. The monthly average difference during the 12 months ended September 30, 2007 ranged from 6% to 24%. In contrast to the Homer City facilities, during the past 12 months, the prices at the Northern Illinois Hub were substantially the same as those at the individual busbars of the Illinois plants, although the implementation of marginal losses on June 1, 2007 has lowered energy prices at the Illinois plants busbars.

By entering into cash settled futures contracts and forward contracts using the PJM West Hub and the Northern Illinois Hub (or other similar trading hubs) as settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME may purchase financial transmission rights and basis swaps in PJM for EME Homer City. A financial transmission right is a financial instrument that entitles the holder to receive the difference of actual spot prices for two delivery points in exchange for a fixed amount. Accordingly, EME’s hedging activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

The Illinois plants and the Homer City facilities purchase coal primarily obtained from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements extending through 2010. The following table summarizes the amount of coal under contract at September 30, 2007 for the remainder of 2007 and the following three years.

EME is subject to price risk for purchases of coal that are not under contract. Prices of NAPP coal, which are related to the price of coal purchased for the Homer City facilities, increased during the first nine months of 2007 from 2006 year-end prices. The price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO₂ per MMBtu sulfur content) increased to $46.25 per ton at September 28, 2007 from $43.00 per ton at December 15, 2006, as reported by the Energy Information Administration. The 2007 increase in the NAPP coal price was in line with normal market price volatility. The price of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO₂ per MMBtu sulfur content) purchased for the Illinois plants increased to $10.55 per ton at September 28, 2007 from $9.90 per ton at December 15, 2006, as reported by the Energy Information Administration. The 2007 fluctuations in PRB coal prices were in line with normal market price volatility.

EME has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers), which extends through 2011. EME is exposed to price risk

related to higher transportation rates after the expiration of its existing transportation contracts. Current transportation rates for PRB coal are higher than the existing rates under contract (transportation costs are more than 50% of the delivered cost of PRB coal to the Illinois plants).

The federal Acid Rain Program requires electric generating stations to hold SO₂ allowances, and Illinois and Pennsylvania regulations implemented the federal NO_X SIP Call requirement. As part of the acquisition of the Illinois plants and the Homer City facilities, EME obtained the rights to the emission allowances that have been or are allocated to these plants. EME purchases (or sells) emission allowances based on the amounts required for actual generation in excess of (or less than) the amounts allocated under these programs. The average price of purchased SO₂ allowances decreased to $521 per ton during the first nine months of 2007 from $664 per ton during 2006. The price of SO₂ allowances, determined by obtaining broker quotes and information from other public sources, was $558 per ton as of October 31, 2007.

For a discussion of environmental regulations related to emissions, refer to “Other Developments—Environmental Matters” in the year-ended 2006 MD&A.

EME uses a number of energy contracts to manage exposure from changes in the price of electricity, including forward sales and purchases of physical power and forward price swaps which settle only on a financial basis (including futures contracts). EME follows SFAS No. 133, and under this Standard these energy contracts are generally defined as derivative financial instruments. Importantly, SFAS No. 133 requires changes in the fair value of each derivative financial instrument to be recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting under the terms of SFAS No. 133. For derivatives that do qualify for cash flow hedge accounting, changes in their fair value are recognized in other comprehensive income until the hedged item settles and is recognized in earnings. However, the ineffective portion of a derivative that qualifies for cash flow hedge accounting is recognized currently in earnings. For further discussion of derivative financial instruments, see “EMG: Market Risk Exposures—MEHC’s Accounting for Energy Contracts” in the year-ended 2006 MD&A.

SFAS No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies under SFAS No. 133 from accrual accounting (i.e., revenue recognition based on settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from energy contracts as part of operating revenues. The results of derivative activities are recorded as part of cash flows from operating activities in the consolidated statements of cash flows.

The following table summarizes unrealized gains (losses) from non-trading activities for the third quarters of 2007 and 2006 and nine months ended September 30, 2007 and 2006:

The following table summarizes the fair values for outstanding derivative financial instruments (used in) EME’s continuing operations for purposes other than trading, by risk category:

In assessing the fair value of EME’s non-trading derivative financial instruments, EME uses a variety of methods and assumptions based on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The change in fair value of electricity contracts at September 30, 2007 as compared to December 31, 2006 is attributable to an increase in the average market prices for power as compared to contracted prices at September 30, 2007, which is the valuation date, causing the fair value of the contracts to become liabilities instead of assets. The following table summarizes the maturities and the related fair value, based on actively traded prices, of EME’s commodity derivative assets and liabilities as of September 30, 2007:

The fair value of the commodity financial instruments related to energy trading activities as of September 30, 2007 and December 31, 2006, are set forth below:

The change in the fair value of trading contracts for the nine months ended September 30, 2007, was as follows:

Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated electric utility that EME’s subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME’s subsidiary recorded these agreements at fair value based upon a discounting of future electricity prices derived

from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of September 30, 2007):

In conducting EME’s hedging and trading activities, EME contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with re-contracting the product at a price different from the original contracted price if the non-performing counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time a counterparty defaulted.

To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. EME measures, monitors and mitigates credit risk to the extent possible. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or lower credit exposure. Processes have also been established to determine and monitor the creditworthiness of counterparties. EME manages the credit risk on the portfolio based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. A risk management committee regularly reviews the credit quality of EME’s counterparties. Despite this, there can be no assurance that these efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate.

The credit risk exposure from counterparties of merchant energy activities (excluding load requirements services contracts) are measured as either: (i) the sum of 60 days of accounts receivable, current fair value of open positions, and a credit value at risk, or (ii) the sum of delivered and unpaid accounts receivable and the current fair value of open positions. EME’s subsidiaries enter into master agreements and other arrangements in conducting hedging and trading activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME’s credit risk exposure from counterparties is based on net exposure under these agreements. At September 30, 2007, the amount of exposure as described above, broken down by the credit ratings of EME’s counterparties, was as follows:

EME’s plants owned by unconsolidated affiliates in which EME owns an interest sell power under power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a power purchase agreement, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of such power plant.

In addition, coal for the Illinois plants and the Homer City facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers to the Illinois plants and the Homer City facilities do not currently have an investment grade credit rating and, accordingly, EME may have limited recourse to collect damages in the event of default by a supplier. EME seeks to mitigate this risk through diversification of its coal suppliers and through guarantees and other collateral arrangements when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from coal suppliers.

EME’s merchant plants sell electric power generally into the PJM market by participating in PJM’s capacity and energy markets or transact capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 51% of EME’s consolidated operating revenue for the nine months ended September 30, 2007. Moody’s rates PJM’s senior unsecured debt Aa3. PJM, an ISO with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared by all other members based upon a predetermined formula. At September 30, 2007, EME’s account receivable due from PJM was $92 million.

Beginning in January 2007, EME also derived a significant source of its revenue from the sale of energy, capacity and ancillary services generated at the Illinois plants to Commonwealth Edison under load requirements services contracts. Sales under these contracts accounted for 19% of EME’s consolidated operating revenue during the nine months ended September 30, 2007. Commonwealth Edison’s senior unsecured debt rating was downgraded below investment grade by S&P in October 2006 and by Moody’s in March 2007. As a result, Commonwealth Edison is required to pay EME twice a month for sales under these contracts. At September 30, 2007, EME’s account receivable due from Commonwealth Edison was $21 million.

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME’s consolidated long-term obligations (including current portion) was $3.8 billion at September 30, 2007, compared to the carrying value of $3.8 billion.

Edison Capital holds a minority interest as a limited partner in three separate funds that invest in infrastructure assets in Latin America, Asia and countries in Europe with emerging economies. As of September 30, 2007, Edison Capital had investments in Latin America, Asia and Emerging Europe of $26 million, $19 million and $16 million, respectively. Edison Capital, through these investments, is exposed to foreign exchange risk in the currency of the ultimate investment.

Edison Capital’s cross-border leases are denominated in U.S. dollars and, therefore, are not exposed to foreign current rate risk.

The parent company’s liquidity and its ability to pay interest and principal on debt, if any, operating expenses and dividends to common shareholders are affected by dividends and other distributions from subsidiaries, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to capital markets or external financings. As of September 30, 2007, Edison International had no debt outstanding (excluding intercompany related debt).

Edison International (parent)’s cash requirements for the 12-month period following September 30, 2007 are expected to consist of:

Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand, borrowings and dividends from its subsidiaries. At September 30, 2007, Edison International (parent) had approximately $11 million of cash and cash equivalents on hand. On February 23, 2007, Edison International amended its credit facility, increasing the amount of borrowing capacity to $1.5 billion and extending the maturity to February 2012. At September 30, 2007, the entire credit facility was available for liquidity purposes. The ability of subsidiaries to make dividend payments to Edison International is dependent on various factors as described below.

SCE may pay dividends to Edison International subject to CPUC restrictions. The CPUC regulates SCE’s capital structure by requiring that SCE maintain prescribed percentages of common equity, preferred equity and long-term debt in the utility’s capital structure. SCE may not make any distributions to Edison International that would reduce the common equity component of SCE’s capital structure below the authorized level on a 13-month weighted average basis (see “SCE: Liquidity—Dividend Restrictions and Debt Covenants” for further discussion). The CPUC also requires that SCE establish its dividend policy as though it were a comparable stand-alone utility company and give first priority to the capital requirements of the utility as necessary to meet its obligation to serve its customers. Other factors at SCE that affect the amount and timing of dividend payments by SCE to Edison International include, among other things, SCE’s capital requirements, SCE’s access to capital markets, payment of dividends on SCE’s preferred and preference stock, and actions by the CPUC. The Board of Directors of SCE declared a $60 million dividend to Edison International which was paid in January 2007 and quarterly dividends of $25 million which were paid in April 2007, July 2007, and October 2007.

EMG’s ability to pay dividends is dependent on its subsidiaries ability to pay dividends to EMG. EME’s corporate credit facility contains covenants that restrict its ability, and the ability of several of its subsidiaries, to pay dividends in the case of any event of default under the facility. As of September 30, 2007, EME was not in default under its credit facility. In addition, see “EMG: Liquidity—Dividend Restrictions in Major Financings” section for further discussion. During 2007, EMG made dividend payments of $238 million to Edison International from distributions received from Edison Capital.

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994 to 1996 and 1997 to 1999 tax years, respectively. Edison International has protested certain issues which are currently being addressed at the IRS administration appeals phase of the audit. See “Other Developments—Federal and State Income Taxes” for further discussion of these matters.

The following sections of the MD&A are on a consolidated basis and should be read in conjunction with individual subsidiary discussion.

The following subsections of “Results of Operations and Historical Cash Flow Analysis” provide a discussion on the changes in various line items presented on the Consolidated Statements of Income, as well as a discussion of the changes on the Consolidated Statements of Cash Flows.

The table below presents Edison International’s earnings and earnings per common share for the three- and nine-month periods ended September 30, 2007 and 2006, and the relative contributions by its subsidiaries.

Edison International’s earnings from continuing operations were $465 million and $886 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to $460 million and $817 million for the respective periods in 2006.

SCE’s earnings from continuing operations were $262 million and $587 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to $263 million and $618 million for the respective periods in 2006. The quarter earnings reflect an increase primarily related to higher net revenue associated with the 2006 GRC, partially offset by a benefit from a generator settlement recorded in the third quarter of 2006. SCE’s year-to-date decrease reflects a benefit recorded in 2006 related to the resolution of an issue related to state income taxes and the generator settlement, partially offset by a benefit recorded in 2007 primarily reflecting

progress on an appeal with the IRS related to the income tax treatment of certain costs associated with environmental remediation and higher net revenue associated with the 2006 GRC and lower income taxes.

EMG’s earnings from continuing operations were $207 million and $313 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to $204 million and $221 million for the respective periods in 2006. The quarter increase was primarily due to lower net interest expense from debt repayment and higher energy margins, partially offset by higher development and corporate costs. The year-to-date variance reflects higher energy margins at EMG’s Illinois plants and EMG’s Homer City facilities and higher project income and higher contribution from Edison Capital, partially offset by higher development and corporate costs. The year-to-date variance also reflects after-tax charges primarily associated with early debt extinguishment.

SCE’s retail sales represented approximately 87% of electric utility revenue for both the three- and nine-month periods ended September 30, 2007, respectively, compared to approximately 90% for both comparable periods in 2006. Due to warmer weather during the summer months and SCE’s rate design, electric utility revenue during the third quarter of each year is generally higher than other quarters.

Total electric utility revenue increased by $134 million and $77 million for the three- and nine-month periods ended 2007, respectively (as shown in the table above). The variances for the revenue components are as follows:

Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE’s customers, CDWR bond-related costs and a portion of direct access exit fees are remitted to the CDWR and none of these collections are recognized as revenue by SCE. These amounts were $671 million and $1.8 billion for the three- and nine-month periods ended September 30, 2007, respectively, compared to $686 million and $1.8 billion for the same respective periods in 2006.

Nonutility power generation revenue increased $7 million and $278 million for the three- and nine-month periods ended September 30, 2007, respectively.

Nonutility power generation revenue from EMG’s Illinois plants increased $11 million and $164 million for the three- and nine-month periods ended September 30, 2007, respectively. The 2007 year-to-date increase was attributable to higher energy revenue resulting from higher generation and average realized energy prices as compared to 2006. Nonutility power generation revenue from EMG’s Illinois plants was also adversely affected by an increase in unrealized losses in 2007 related to hedge contracts. EMG’s Illinois plants recorded unrealized losses of $8 million and $26 million for the three- and nine-month period ended September 30, 2007, compared to unrealized gains of $6 million and $17 million for the respective periods in 2006. Unrealized gains and losses are primarily due to power contracts that did not qualify for hedge accounting under SFAS No. 133 (sometimes referred to as economic hedges). These energy contracts were entered into to hedge the price risk related to projected sales of power. During 2007, power prices increased, resulting in mark-to-market losses on economic hedges. At September 30, 2007, EMG’s Illinois plants had unrealized losses of $19 million related to subsequent periods, primarily from economic hedges and from the ineffective portion of cash flow hedges. The ineffective portion of hedge contracts at the Illinois plants was primarily attributable to changes in the difference between energy prices at NiHub (the settlement point under forward contracts) and the energy prices at the Illinois plants busbars (the delivery point where power generated by the Illinois plants is delivered into the transmission system) resulting from marginal losses. See “EMG: Market Risk Exposures—Commodity Price Risk” for more information regarding forward market prices.

Nonutility power generation from EMG’s Homer City facilities increased $100 million for the nine-month period ended September 30, 2007. The 2007 increase was primarily attributable to an increase in energy revenue from higher generation and average realized energy prices, and an increase in capacity revenue resulting from the PJM RPM auction. On January 29, 2006, the main power transformer on Unit 3 of the EMG Homer City facilities failed resulting in a suspension of operations at this unit. Homer City secured a replacement transformer and

Unit 3 returned to service on May 5, 2006. The Unit 3 outage reduced the amount of generation during the nine months ended September 30, 2006. Nonutility power generation revenue from EMG’s Homer City facilities was adversely affected due to the timing of unrealized gains and losses related to hedge contracts. EMG’s Homer City facilities recorded unrealized losses of $3 million and $5 million for the three- and nine-month period ended September 30, 2007, compared to unrealized gains of $16 million and $20 million for the respective periods in 2006. Unrealized gains and losses were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. The ineffective portion of hedge contracts at Homer City was primarily attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). At September 30, 2007, EMG’s Homer City had unrealized losses of $16 million related to subsequent periods primarily from the ineffective portion of cash flow hedges related to subsequent periods. See “EMG: Market Risk Exposures—Commodity Price Risk” for more information regarding forward market prices.

EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel and transmission congestion primarily in the eastern power grid using products available over the counter, through exchanges and from ISOs. Nonutility power generation revenue from energy trading activities at EMMT decreased $13 million and $6 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The decrease in nonutility power generation revenue from energy trading activities was primarily attributable to less transmission congestion in 2007 due in part to a milder summer in July 2007 as compared to July 2006.

Due to higher electric demand resulting from warmer weather during the summer months and cold weather during the winter months, nonutility power generation revenue from EMG’s Illinois plants and Homer City facilities vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall) further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, nonutility power generation revenue from EMG’s Illinois plants and Homer City facilities are seasonal and have significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. See “EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Illinois Plants” and “—Energy Price Risk Affecting Sales from the Homer City Facilities” for further discussion regarding market prices.

SCE’s fuel expense increased $24 million and $68 million for the three- and nine-month periods ended September 30, 2007, respectively, as compared to the same periods in 2006. The quarter and year-to-date increases were mainly due to an increase at Mountainview of $30 million and $65 million for the three- and nine-month periods ended September 30, 2007, respectively, due to higher generation in 2007 compared to 2006. Also contributing to the increase was higher nuclear fuel expense of $25 million for the nine-month period ended September 30, 2007 resulting primarily from a planned refueling and maintenance outage at SCE’s San Onofre

Unit 2 and 3 in 2006. The quarter and year-to-date increases were partially offset by lower fuel expense of approximately $10 million and $25 million, respectively, related to the SCE VIE projects.

EMG’s fuel expense decreased $8 million and increased $31 million for the three- and nine-month periods ended September 30, 2007, respectively. The year-to-date increase was mainly due to higher generation at EMG’s Illinois plants and Homer City facilities.

Purchased-power expense increased $248 million and decreased $388 million for the three and nine months ended September 30, 2007, as compared to the same periods in 2006. The quarter and year-to-date variances reflect an increase in bilateral energy purchases of $110 million and $95 million for the three- and nine-month periods ended September 30, 2007, respectively, resulting from greater power demand; lower energy settlement refunds of approximately $120 million and $150 million for the three-and nine month periods ended September 2007, respectively; higher QF purchased power expense of $25 million and $15 million for the three- and nine-months ended September 30, 2007, respectively, resulting from an increase in the average spot natural gas prices (as discussed further below). The quarter and year-to-date increases were partially offset by a decrease in ISO-related energy costs of $35 million and $110 million, for the three- and nine-month periods ended September 30, 2007, respectively. The year-to-date variance also reflects net realized and unrealized losses on economic hedging activities of $88 million compared to $630 million for the nine-month periods ended September 30, 2007 and 2006, respectively (see “SCE: Market Risk Exposures—Commodity Price Risk” for further discussion). The changes in net unrealized (gains) losses on economic hedging activities primarily resulted from changes in SCE’s gas hedge portfolio mix as well as the movements in the natural gas futures market. The changes in net realized losses on economic hedging activities primarily resulted from a more stable natural gas market in 2007. Due to expected recovery through regulatory mechanisms unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings.

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

Provisions for regulatory adjustment clauses – net decreased $181 million and increased $445 million for the three- and nine-month periods ended September 30, 2007, respectively, as compared to the same periods in 2006. The quarter and year-to-date variances reflect net unrealized losses on economic hedging activities of $67 million

and $9 million for three-month periods ended September 30, 2007 and 2006, respectively, and net unrealized gains on economic hedging activities of approximately $23 million for the nine-month period ended September 30, 2007, compared to $351 million of net unrealized losses for the same period last year (mentioned above in purchased-power expense). The quarter and year-to-date variance also reflects a $60 million FERC refund settlement recorded in 2006. The year-to-date increase also reflects the resolution of a $135 million one-time gain related to a portion of revenue collected during the 2001 – 2003 period related to state income taxes recorded in the second quarter of 2006. The quarter and year-to-date variances also reflect timing differences for operation and maintenance-related expenses that are recovered through regulatory mechanisms.

SCE’s other operation and maintenance expense increased $65 million and $78 million for the three- and nine-month periods ended September 30, 2007, respectively, as compared to the same periods in 2006. The quarter and year-to-date increases were mainly due to higher demand-side management and energy efficiency costs of approximately $40 million and $95 million for the three- and nine-month periods ended September 30, 2007, respectively, (which are recovered through regulatory mechanisms approved by the CPUC) and higher transmission and distribution maintenance cost of approximately $5 million and $25 million for the three- and nine-month period ended September 30, 2007, respectively. This year-to-date increase was partially offset by lower must-run and must-offer obligation costs of $40 million related to the reliability of the ISO systems and lower generation-related costs of approximately $35 million for the nine months ended September 30, 2007 resulting from the planned refueling and maintenance outages at SCE’s San Onofre Units 2 and 3 in the first quarter 2006.

EMG’s other operation and maintenance expense increased $40 million and $88 million for the three- and nine-month periods ended September 30, 2007, respectively, mainly due to higher planned maintenance costs at EMG’s Illinois plants and higher development costs incurred in 2007 (mostly related to wind projects), higher corporate expenses and a loss accrual related to legal proceedings recorded in the third quarter of 2007. See “EMG: Liquidity—Business Development.” The year-to-date increase was also due to higher maintenance costs in 2007 at EMG’s Homer City facilities related to the planned outage at Unit 2.

SCE’s depreciation, decommissioning and amortization expense increased $13 million and $7 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to the same periods in 2006 primarily due to transmission and distribution asset additions resulting in increased depreciation expense of

$15 million and $30 million for the three- and nine-month periods ended September 30, 2007, respectively. (see “SCE: Liquidity—Capital Expenditures” for a further discussion). In addition, the variance reflects a decrease in decommissioning expense of $1 million and $20 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to the same periods in 2006 primarily resulting from other-than-temporary impairment losses associated with the nuclear decommissioning trust funds, partially offset by an increase in trust earnings. Due to its regulatory treatment, investment impairment losses and trust earnings are recorded in electric utility revenue and are offset in decommissioning expense and have no impact on net income.

SCE’s interest income decreased $1 million and $10 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to the same periods in 2006, mainly due to lower interest income resulting from lower undercollections on certain balancing accounts in 2007, as compared to 2006.

EMG’s interest and dividend income decreased $2 million and increased $11 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to the same periods in 2006. The year-to-date increase was mainly due to the recognition of distributions received from EMG’s Doga project in 2007.

Equity in income from partnerships and unconsolidated subsidiaries – net decreased $4 million and increased $19 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to the same period in 2006. The variance was mainly due to lower earnings of $7 million and higher earnings of $12 million for the three- and nine-month periods ended September 30, 2007, respectively, from Edison Capital’s global infrastructure funds.

SCE’s other nonoperating income increased $16 million and $7 million for the three- and nine-month periods ended September 30, 2007, compared to the same periods in 2006. The increase was primarily due to payments received in settlement of claims related to the natural gas purchased contracts for one of SCE’s VIE projects.

EMG’s other nonoperating income increased $3 million and decreased $23 million for the three- and nine-month periods ended September 30, 2007, compared to the same period in 2006. The year-to-date decrease is due to estimated insurance recovery related to EMG’s Homer City Unit 3 outage of approximately $11 million recorded in the second quarter of 2006, compared to $3 million recorded during the third quarter of 2007. The Homer City main transformer failure resulted in claims under Homer City’s property and business interruption insurance policies. At September 30, 2007, EMG’s Homer City had a $16 million receivable recorded related to these claims. The year-to-date decrease also reflects an $8 million gain related to the receipt of shares from Mirant Corporation from settlement of a claim and a $4 million gain resulting from EMG’s sale of 25% of its ownership interest in the San Juan Mesa wind project to Citi Renewable Investments I LLC, both recognized in the first quarter of 2006.

SCE’s interest expense – net of amounts capitalized increased $19 million and $33 million for the three- and nine-month periods ended September 30, 2007, respectively, mainly due to higher interest expense on balancing account overcollections in 2007, as compared to 2006. The increase was also due to higher interest expense on long-term debt resulting from higher balances outstanding as of September 30, 2007, compared to the same period in 2006.

EMG’s interest expense—net of amounts capitalized decreased $28 million and $64 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to the same periods in 2006. The decreases were primarily attributable to MEHC’s redemption in full of its senior secured notes in June 2007, and an increase in capitalized interest due to wind projects under construction. The variances are also attributable to $2.7 billion of new debt entered into by EME as part of its refinancing activities in May 2007 (See EMG: Current Developments—Refinancing).

Loss on early extinguishment of debt was $241 million for the nine-month period ended September 30, 2007 related to the early repayment of EME’s 7.73% senior notes due June 15, 2009, Midwest Generation’s 8.75% second priority senior secured notes due May 1, 2034, and MEHC’s 13.5% senior secured notes due July 15, 2008.

Loss on early extinguishment of debt was $143 million for the nine-month period ended September 30, 2006 related to the early repayment of EME’s 10% senior notes due August 15, 2008 and 9.875% senior notes due April 15, 2011.

Edison International’s income (loss) from discontinued operations were $(4) million and $1 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to $(2) million and $75 million for the same periods in 2006. The variance was largely attributable to distributions received from the Lakeland project.

Effective January 1, 2006, Edison International adopted SFAS No. 123(R) that requires the fair value accounting method for stock-based compensation. Implementation of SFAS No. 123(R) resulted in a $1 million, after-tax, cumulative-effect adjustment in the first quarter of 2006.

The “Historical Cash Flow Analysis” section of this MD&A discusses consolidated cash flows from operating, financing and investing activities.

Cash provided by operating activities from continuing operations decreased $264 million in the first nine months of 2007, compared to the first nine months of 2006. The 2007 change reflects an increase of $36 million in required margin and collateral deposits in the first nine months of 2007 for EMG’s hedging and trading activities, compared to a decrease of $500 million in the first nine months of 2006. This change resulted from an increase in forward market prices in 2007 compared to 2006. The 2007 change also reflects a decrease in revenue collected from SCE’s customers primarily due to lower rates in 2007, compared to 2006. On February 14, 2007, SCE reduced its system average rate mainly as the result of estimated lower natural gas prices in 2007, the refund of overcollections in the ERRA balancing account that occurred in 2006 and the impact of the redesign of SCE’s tiered rate structure in 2007 (see “SCE: Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates” for further discussion). The 2007 change was also due to the timing of cash receipts and disbursements related to working capital items.

Cash provided by operating activities from discontinued operations decreased $81 million in the first nine months of 2007, compared to the same period in 2006. The 2007 decrease reflects higher distributions received in 2006, compared to 2007, from EMG’s Lakeland power project. See “Discontinued Operations” in the year-ended 2006 MD&A for more information regarding these distributions.

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

Financing activities in 2006 included activities related to the rebalancing of SCE’s capital structure and rate base growth and the reduction of debt at EMG, as follows:

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

Net cash used by investing activities for the first nine months of the year was $2.1 billion in 2007 and $2.0 billion in 2006.

Investing activities in 2007 reflect $1.65 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $104 million for nuclear fuel acquisitions, and $329 million in capital expenditures at EMG. Investing activities also include higher turbine deposits (net of deposit refunds of $112 million) at EMG, net maturities and sales of short term investments of $206 million, and $11 million in payments made towards the purchase price of EMG’s Wildorado wind project during the second quarter of 2007.

Investing activities in 2006 reflect $1.6 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $63 million for nuclear fuel acquisitions, and $142 million in capital expenditures at EMG largely related to the wind projects. In addition, investing activities include net purchases of short term investments of $156 million as well as the receipt of $43 million in proceeds from the sale of 25% of EME’s ownership interest in the San Juan Mesa wind project. EMG also paid $18 million towards the purchase price of the Wildorado wind project during the first quarter of 2006.

The following is an update to Edison International’s commitments, guarantees and indemnities. See the section, “Commitments, Guarantees, and Indemnities,” in the year-ended 2006 MD&A for a detailed discussion.

As of September 30, 2007, Edison International’s long-term debt maturities (including forecast interest payments) and sinking fund requirements for the next five years are: remaining 2007 – $364 million; 2008 – $578 million; 2009 – $726 million; 2010 – $844 million; 2011 – $540 million; and thereafter – $15 billion. These amounts have been updated primarily to reflect EME’s financing activities completed during the second quarter of 2007. See “EMG: Current Developments—Refinancing” for additional details.

contractual obligations for transportation are based on coal volumes set forth in fuel supply contracts. The increase in transportation commitments entered into during the first nine months of 2007 relates to additional volumes of fuel purchases using the terms of existing transportation agreements. These additional commitments are currently estimated to be $18 million for the remainder of 2007, $111 million for 2008, $76 million for 2009, and $77 million for 2010.

At September 30, 2007, Edison International had a total net liability recorded for uncertain tax positions of $324 million. Edison International cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing of resolving these open tax issues with the IRS.

Mountainview owns and operates a power plant in Redlands, California. The plant utilizes water from on-site groundwater wells and City of Redlands (city) recycled water for cooling purposes. Unrelated to the operation of the plant, this water contains perchlorate. The pumping of the water removes perchlorate from the aquifer beneath the plant and concentrates it in the plant’s wastewater treatment “filter cake.” Use of this impacted groundwater for cooling purposes was mandated by Mountainview’s California Energy Commission permit. Mountainview has indemnified the city for cleanup or 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.

The operating affiliates of Edison International are subject to numerous federal and state environmental laws and regulations, which require them to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. Edison International believes that its operating affiliates are in substantial compliance with existing environmental regulatory requirements.

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

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

On December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NOX and SO2 emissions at the Illinois plants. The agreement has been embodied in rule language, called the CPS, and Midwest Generation’s obligations under the agreement were conditioned upon the formal adoption of the CPS as an Illinois rule. On January 5, 2007, the Illinois EPA and Midwest Generation jointly filed the CPS in the pending state rulemaking related to the Illinois SIP for the CAIR. The CPS was approved by the Joint Committee on Administrative Rules on August 14, 2007, and became final upon publication in the Illinois Register, which took place on September 7, 2007. It is now pending approval by the US EPA as part of the SIP. Midwest Generation believes that the CPS will provide greater predictability of the timing and amount of emissions reductions which will be required of the Illinois plants for these pollutants through 2018.

The Pennsylvania SIP for the Clean Air Mercury Rule is pending approval by the US EPA. It was published in the Federal Register on September 18, 2007 and the comment period ended on October 15, 2007. The SIP is expected to become effective in 2010. EME Homer City intends to comply with the rule using its existing scrubber at one of its units, supplemented by a combination of carbon injection and coal washing at the other two units.

The proposed Pennsylvania CAIR is expected to be approved by the Pennsylvania Environmental Quality Board in late 2007 and subsequently submitted to the US EPA for approval. EME Homer City will be subject to the Federal CAIR rule during 2009 and expects to be able to comply with the NO_X requirement using its existing SCR system. The Pennsylvania CAIR, including both NO_X and SO₂ limits, is expected to become effective in 2010, at which time EME Homer City expects to purchase SO₂ allowances.

On July 31, 2007, the US EPA issued a NOV to Midwest Generation and Commonwealth Edison with respect to alleged violations of the Clean Air Act and certain opacity and particulate matter standards. See “EMG: Other Developments—Midwest Generation Potential Environmental Proceeding” for further discussion.

On July 9, 2007, the US EPA published in the Federal Register a notice immediately suspending the requirements for cooling water intake structures, pending further rulemaking. The US EPA is expected to issue a proposed rule by the end of 2008. Although the rule to be generated in the new rulemaking process could have a material impact on Edison International’s operations, its compliance criteria have not yet been finalized, and Edison International cannot reasonably determine the financial impact at this time.

EME Homer City and the Pennsylvania Department of Environmental Protection have entered into a consent order and agreement related to selenium discharge, which was filed in Pennsylvania state court on July 17, 2007. Under the consent order and agreement, EME Homer City agreed to pay a civil penalty of $200,000 and to install modifications to its wastewater system to achieve consistent compliance with discharge limits. Until the pilot programs have been completed and the treatment system design has been finalized, EME will be unable to estimate the costs for ongoing treatment.

On October 26, 2007, the Illinois Environmental Protection Agency filed a proposed rule with the Illinois Pollution Control Board that would establish new, more stringent thermal and effluent water quality standards for the Chicago Area Waterway System and Lower Des Plaines River. Midwest Generation’s Fisk, Crawford, Joliet and Will County stations all use water from the affected waterways for cooling purposes and the rule is expected to affect the manner in which those stations use water for station cooling.

The proposed rule will be the subject of an administrative proceeding before the Illinois Pollution Control Board and must be approved by the Board and the Illinois Joint Committee on Administrative Rules. Following state adoption and approval, the US EPA also must approve the rule. Midwest Generation intends to participate as a party in those proceedings and in any subsequent appellate proceedings. At this time, it is not possible to predict the final form of the rule, how it would impact the operation of the affected stations, or the possible compliance costs or liability.

In September 2006, California’s Governor Schwarzenegger signed two bills into law regarding GHG emissions. The first, known as AB 32 or the California Global Warming Solutions Act of 2006, establishes a comprehensive program of regulatory and market mechanisms to achieve reductions of GHG emissions. AB 32 requires the CARB to develop regulations and market mechanisms targeted to reduce California’s GHG emissions to 1990 levels by 2020. CARB’s mandatory program will take effect commencing in 2012 and will implement incremental reductions so that GHG emissions will be reduced to 1990 levels by 2020. In addition, AB 32 requires the CARB to adopt regulations to require the reporting and verification of statewide GHG emissions. See “—GHG Reporting/Tracking Regulations” for further discussion. The second bill, known as SB 1368, relates specifically to power generation and requires the CPUC and the CEC to adopt GHG performance standards for investor owned and publicly owned utilities, respectively, for long-term procurement of electricity. The standards must equal the performance of a combined-cycle gas turbine generator. The CPUC adopted such a standard on January 25, 2007 (which limits emissions to 1,100 pounds of carbon dioxide per MWh). On August 29, 2007, the CEC adopted regulations pursuant to SB 1368 establishing and implementing a GHG EPS for baseload generation of local publicly owned electric utilities.

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

On April 2, 2007, the United States Supreme Court issued an opinion in Massachusetts et. al. v. Environmental Protection Agency, et. al., ruling that the US EPA has the authority to regulate greenhouse gas emissions of new motor vehicles under the Clean Air Act and that it has a duty to (i) determine whether greenhouse gas emissions of new motor vehicles contribute to climate change or (ii) offer a reasoned explanation for its failure to make such a determination when presented with a request for a rulemaking on the issue by the state claimants. The Court ruled that the US EPA’s failure to make the necessary determination or offer a reasonable explanation for its refusal to do so was impermissible. While this case hinged on a provision of the Clean Air Act related to emissions of motor vehicles, a parallel provision of the Clean Air Act applies to stationary sources such as electric generators. The US EPA has recently announced that it plans to propose regulations to address carbon dioxide emissions as part of the Clean Air Act’s New Source Review program. Even in the absence of federal regulation, states may begin to take into account carbon dioxide emissions when considering permits to construct or modify significant sources of such emissions. EME also believes that the Court’s Massachusetts decision may spur additional congressional action to require reductions of greenhouse gas emissions by all material sources, including electric generators.

AB 32 requires the CARB to adopt regulations to require the reporting and verification of statewide GHG emissions on or before January 1, 2008. In September 2007, the CPUC and the CEC approved a joint decision recommending that the CARB adopt the proposed GHG emissions reporting and verification protocol for the electricity sector that was set forth in the joint decision. The CPUC’s and CEC’s proposed reporting and verification protocol includes specific GHG emissions reporting requirements for retail providers and marketers in the electricity sector, and would be applicable to SCE. The CARB issues its own proposed regulations for the reporting of GHG emissions (including the reporting of GHG emissions for the electricity sector) on October 19, 2007 for public comment. The CARB will consider the adoption of such proposed regulations at its December 6-7, 2007 meeting. SCE cannot estimate its total cost of compliance with the CARB’s reporting regulations until the final regulations are adopted.

Edison International remains subject to examination and administrative appeals by the IRS for tax years 1994 –present. Edison International is challenging certain IRS examination adjustments for tax years 1994 – 1999 with the Administrative Appeals branch of the IRS and Edison International is currently under IRS examination for tax years 2000 – 2002. In addition, the statute of limitations remains open for tax years 1986 – 1993 for certain affirmative claims.

As of September 30, 2007, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $489 million. The IRS also seeks a 20% penalty on any sustained tax adjustment.

Progress continued during the first nine months of 2007 on preparation for the installation of an enterprise resources planning application from SAP. On July 2, 2007, Edison International implemented procurement and material management systems at three of EMG’s Illinois plants, as well as the EME financial systems. Implementation of these applications at the remaining Illinois plants and Homer City facilities began on September 1, 2007, and implementation of a fuel management system began on October 1, 2007. EME plans to implement the human resources systems in conjunction with the SCE human resource implementation. SCE is scheduled to implement financial, procurement, material management, work management and human resources systems in mid-2008.

Two of the Big 4 projects (the Sycamore project and the Watson project) have power purchase agreements with SCE. Under FIN46(R), Edison International and SCE consolidate these projects due to SCE’s variable interest in these entities. The power purchase agreements with SCE and steam agreements with offtakers expire within the next six months. Discussions on extending the power purchase and steam agreements are underway, but no assurance can be given that such discussions will lead to extensions of these agreements. If an extension is not obtained, these projects expect to be able to sell power to SCE under agreements with pricing set forth by the CPUC. In either case, Edison International expects that earnings from the Watson and Sycamore projects will decrease materially after the expiration of the current agreements. Any reduced costs to SCE resulting from these discussions will not impact SCE earnings because the savings flow through the regulatory recovery process to customers.

Information responding to Part I, Item 3 is included in Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” under the headings “SCE: Market Risk Exposures” and “EMG: Market Risk Exposures.”

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

There were changes as described below in EME’s internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the quarter to which this report relates that have materially affected, or are reasonably likely to materially affect EME’s and Edison International’s internal control over financial reporting.

During the third quarter of 2007, EME implemented a series of SAP ERP modules, including a new general ledger and chart of accounts and new consolidation, reporting, and accounts payable. In addition, procurement and materials management systems were implemented for the Illinois Plants and the Homer City facilities. EME’s human resources module will be implemented in 2008 as part of Edison International’s ERP implementation. The introduction of these ERP modules and the related workflow capabilities resulted in changes to EME’s financial reporting controls and procedures, with such changes identified during the implementation of the ERP modules. Therefore, as appropriate, EME is modifying the design and documentation of internal control process and procedures relating to the new system to supplement and complement existing internal controls over financial reporting. The system changes were undertaken to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in EME’s internal control over financial reporting.

Information about the Navajo Nation litigation appears in the MD&A under the heading “SCE: Regulatory Matters—Navajo Nation Litigation”.

Catalina South Coast Air Quality Management District Potential Environmental Proceeding

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

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

Settlement negotiations with the SCAQMD regarding the penalties are ongoing and the SCAQMD has not yet proposed any specific fines to be imposed on SCE.

Information about the US EPA NOV issued to Midwest Generation appears in the MD&A under the heading “EMG: Other Developments—Midwest Generation Potential Environmental Proceeding.”

Information about the FERC notice regarding an investigatory proceeding with respect to EMMT appears in the MD&A under the heading “EMG: Other Developments—FERC Notice Regarding Investigatory Proceeding Against EMMT.”

The following table contains information about all purchases made by or on behalf of Edison International or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) of shares or other units of any class of Edison International’s equity securities that is registered pursuant to Section 12 of the Exchange Act.

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


EDISON INTERNATIONAL
(Registrant)

By:		/s/ LINDA G. SULLIVAN
		LINDA G. SULLIVAN Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)


California		95-4137452
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
2244 Walnut Grove Avenue (P. O. Box 976) Rosemead, California		91770
(Address of principal executive offices)		(Zip Code)


Class		Outstanding at October 26, 2007
Common Stock, no par value		325,811,206


Mountainview		Mountainview Power Company, LLC

MRTU		Market Redesign Technical Upgrade

MW		Megawatts

MWh		megawatt-hours

NAPP		Northern Appalachian

Ninth Circuit		United States Court of Appeals for the Ninth Circuit

NO_X		nitrogen oxide

NOI		Notice of Intent

NRC		Nuclear Regulatory Commission

Palo Verde		Palo Verde Nuclear Generating Station

PBR		performance-based ratemaking

PG&E		Pacific Gas & Electric Company

PJM		PJM Interconnection, LLC

POD		Presiding Officer’s Decision

PRB		Powder River Basin

PX		California Power Exchange

QF(s)		Qualifying facility(ies)

RICO		Racketeer Influenced and Corrupt Organization

S&P		Standard & Poor’s

San Onofre		San Onofre Nuclear Generating Station

SCAQMD		South Coast Air Quality Management District

SCE		Southern California Edison Company

SDG&E		San Diego Gas & Electric

SFAS		Statement of Financial Accounting Standards issued by the FASB

SFAS No. 123(R)		Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment (revised 2004)”

SFAS No. 133		Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”

SFAS No. 144		Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”

SFAS No. 157		Statement of Financial Accounting Standards No. 157, “Fair Value Measurements”

SFAS No. 158		Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”

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

SIP(s)		State Implementation Plan(s)

SO₂		sulfur dioxide

US EPA		United States Environmental Protection Agency

VIE(s)		variable interest entity(ies)


		Page No.
Part I. Financial Information

Item 1.	Financial Statements:	1

	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2007 and 2006	1

	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2007 and 2006	2

	Consolidated Balance Sheets – September 30, 2007 and December 31, 2006	3

	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2007 and 2006	5

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	95

Item 4.	Controls and Procedures	95

Part II. Other Information

Item 1.	Legal Proceedings	97

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	98

Item 6.	Exhibits	99

Signature		100


	Three Months Ended September 30,						Nine Months Ended September 30,
In millions, except per-share amounts	2007			2006			2007			2006
	(Unaudited)
Electric utility	$	3,213		$	3,079		$	7,895		$	7,818
Nonutility power generation		711			704			1,952			1,674
Financial services and other		18			19			55			63
Total operating revenue		3,942			3,802			9,902			9,555
Fuel		502			486			1,425			1,326
Purchased power		1,284			1,036			2,431			2,819
Provisions for regulatory adjustment clauses – net		(66	)		115			189			(256	)
Other operation and maintenance		1,013			909			2,893			2,727
Depreciation, decommissioning and amortization		310			293			937			924
Net loss (gain) on sale of utility property and plant		1			—			—			(1	)
Total operating expenses		3,044			2,839			7,875			7,539
Operating income		898			963			2,027			2,016
Interest and dividend income		40			41			125			120
Equity in income from partnerships and unconsolidated subsidiaries – net		35			39			72			53
Other nonoperating income		35			16			75			91
Interest expense – net of amounts capitalized		(191	)		(199	)		(577	)		(608	)
Loss on early extinguishment of debt		—			—			(241	)		(143	)
Other nonoperating deductions		(7	)		(13	)		(31	)		(35	)
Income from continuing operations before tax and minority interest		810			847			1,450			1,494
Income tax expense		263			310			392			516
Dividends on preferred and preference stock of utility not subject to mandatory redemption		13			13			38			38
Minority interest		69			64			134			123
Income from continuing operations		465			460			886			817
Income (loss) from discontinued operations – net of tax		(4	)		(2	)		1			75
Income before accounting change		461			458			887			892
Cumulative effect of accounting change – net of tax		—			—			—			1
Net income	$	461		$	458		$	887		$	893
Weighted-average shares of common stock outstanding		326			326			326			326
Basic earnings (loss) per common share:
Continuing operations	$	1.41		$	1.39		$	2.69		$	2.48
Discontinued operations		(0.01	)		(0.01	)		—			0.23
Total	$	1.40		$	1.38		$	2.69		$	2.71
Weighted-average shares, including effect of dilutive securities		330			330			331			331
Diluted earnings (loss) per common share:
Continuing operations	$	1.40		$	1.39		$	2.67		$	2.48
Discontinued operations		(0.01	)		(0.01	)		—			0.23
Total	$	1.39		$	1.38		$	2.67		$	2.71
Dividends declared per common share	$	0.29		$	0.27		$	0.87		$	0.81


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨


Btu		British Thermal units

CAIR		Clean Air Interstate Rule

CARB		California Air Resources Board

CDWR		California Department of Water Resources

CEC		California Energy Commission

Commonwealth Edison		Commonwealth Edison Company

CPSD		Consumer Protection and Safety Division

CPUC		California Public Utilities Commission

CRRs		Congestion Revenue Rights

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

DOE		United States Department of Energy

DOJ		Department of Justice

DRA		Division of Ratepayer Advocates

DWP		Los Angeles Department of Water & Power

EME		Edison Mission Energy

EME Homer City		EME Homer City Generation L.P.

EMG		Edison Mission Group Inc.

EMMT		Edison Mission Marketing & Trading, Inc.

EPS		Earnings per share

ERRA		energy resource recovery account

Exelon Generation		Exelon Generation Company LLC

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

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

FTR		firm transmission rights

GHG		greenhouse gas

GRC		General Rate Case

IRS		Internal Revenue Service

ISO		California Independent System Operator

kWh(s)		kilowatt-hour(s)

MAAC + APS		Mid-Atlantic Area Council (MAAC) and Allegheny Power (APS)

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

MEHC		Mission Energy Holding Company

Midland Cogen		Midland Cogeneration Venture

Midway-Sunset		Midway-Sunset Cogeneration Company

Midwest Generation		Midwest Generation, LLC

Moody’s		Moody’s Investors Service


	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2007			2006			2007			2006
	(Unaudited)
Net income	$	461		$	458		$	887		$	893
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments:
Other foreign currency translation adjustments – net		1			(3	)		(1	)		(1	)
Pension and postretirement benefits other than pensions:
Minimum pension liability adjustment		—			—			—			(2	)
Amortization of loss and prior service cost – net		—			—			1			—
Unrealized gain (loss) on cash flow hedges:
Other unrealized gain (loss) on cash flow hedges – net		(28	)		94			(149	)		352
Reclassification adjustment for gain (loss) included in net income		12			(11	)		38			(23	)
Other comprehensive income (loss)		(15	)		80			(111	)		326
Comprehensive income	$	446		$	538		$	776		$	1,219


In millions	September 30, 2007			December 31, 2006
	(Unaudited)
ASSETS
Cash and equivalents	$	1,458		$	1,795
Restricted cash		60			59
Margin and collateral deposits		137			124
Receivables, less allowances of $30 and $29 for uncollectible accounts at respective dates		1,282			1,014
Accrued unbilled revenue		506			303
Fuel inventory		119			122
Materials and supplies		307			270
Accumulated deferred income taxes – net		240			203
Derivative assets		201			328
Regulatory assets		295			554
Short-term investments		352			558
Other current assets		206			152
Total current assets		5,163			5,482
Nonutility property – less accumulated provision for depreciation of $1,706 and $1,627 at respective dates		4,703			4,356
Nuclear decommissioning trusts		3,398			3,184
Investments in partnerships and unconsolidated subsidiaries		293			308
Investments in leveraged leases		2,514			2,495
Other investments		112			91
Total investments and other assets		11,020			10,434
Utility plant, at original cost:
Transmission and distribution		18,492			17,606
Generation		1,681			1,465
Accumulated provision for depreciation		(5,050	)		(4,821	)
Construction work in progress		1,584			1,486
Nuclear fuel, at amortized cost		224			177
Total utility plant		16,931			15,913
Regulatory assets		2,825			2,818
Restricted cash		58			91
Margin and collateral deposits		19			4
Derivative assets		129			131
Rent payments in excess of levelized rent expense under plant operating leases		717			556
Other long-term assets		958			832
Total long-term assets		4,706			4,432

Total assets	$	37,820		$	36,261


In millions, except share amounts	September 30, 2007			December 31, 2006
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Long-term debt due within one year	$	236		$	488
Accounts payable		850			926
Accrued taxes		313			155
Accrued interest		204			196
Counterparty collateral		42			36
Customer deposits		217			198
Book overdrafts		254			140
Derivative liabilities		200			181
Regulatory liabilities		1,316			1,000
Other current liabilities		986			983
Total current liabilities		4,618			4,303
Long-term debt		9,056			9,101
Accumulated deferred income taxes – net		5,291			5,297
Accumulated deferred investment tax credits		117			122
Customer advances		158			160
Derivative liabilities		86			86
Power-purchase contracts		25			32
Accumulated provision for pensions and benefits		1,164			1,099
Asset retirement obligations		2,831			2,759
Regulatory liabilities		3,315			3,140
Other deferred credits and other long-term liabilities		1,546			1,267
Total deferred credits and other liabilities		14,533			13,962
Total liabilities		28,207			27,366
Commitments and contingencies (Note 6)
Minority interest		309			271
Preferred and preference stock of utility not subject to mandatory redemption		915			915
Common stock, no par value (325,811,206 shares outstanding at each date)		2,116			2,080
Accumulated other comprehensive income (loss)		(33	)		78
Retained earnings		6,306			5,551
Total common shareholders’ equity		8,389			7,709

Total liabilities and shareholders’ equity	$	37,820		$	36,261


	Three Months Ended September 30,						Nine Months Ended September 30,
In millions	2007			2006			2007			2006
	(Unaudited)
Basic earnings per share - continuing operations:
Income from continuing operations	$	465		$	460		$	886		$	817
Participating securities dividends		(6	)		(7	)		(10	)		(10	)
Income from continuing operations available to common shareholders	$	459		$	453		$	876		$	807
Weighted average common shares outstanding		326			326			326			326
Basic earnings per share - continuing operations	$	1.41		$	1.39		$	2.69		$	2.48

Diluted earnings per share - continuing operations:
Income from continuing operations available to common shareholders	$	459		$	453		$	876		$	807
Income impact of assumed conversions		4			5			9			14
Income from continuing operations available to common shareholders and assumed conversions	$	463		$	458		$	885		$	821
Weighted average common shares outstanding		326			326			326			326
Incremental shares from assumed conversions		4			4			5			5
Adjusted weighted average shares - diluted		330			330			331			331
Diluted earnings per share - continuing operations	$	1.40		$	1.39		$	2.67		$	2.48


	Three Months Ended September 30,					Nine Months Ended September 30,
	(Unaudited)
In millions	2007		2006			2007			2006
Purchased-power from bilateral contracts, QFs, ISO, FTRs and exchange energy	$	1,153	$	1,028		$	2,356		$	2,351
Unrealized (gains) losses on economic hedging activities – net		67		9			(23	)		351
Realized losses on economic hedging activities – net		58		114			111			279
Energy settlements and refunds		6		(115	)		(13	)		(162	)
Total purchased-power expense	$	1,284	$	1,036		$	2,431		$	2,819


			Weighted-Average
	Stock Options		Exercise Price		Remaining Contractual Term (Years)	Aggregate Intrinsic Value
Outstanding at December 31, 2006	14,111,697		$	26.33
Granted	1,791,517		$	47.69
Forfeited	(48,384	)	$	41.31
Exercised	(3,401,104	)	$	22.74
Outstanding at September 30, 2007	12,453,726		$	30.32	6.59
Vested and expected to vest at September 30, 2007	11,950,032		$	29.95	6.53	$	290,893,654
Exercisable at September 30, 2007	6,689,756		$	23.61	5.42	$	205,258,438


In millions	Tax Years Under Appeal 1994 – 1999		Tax Years Under Audit 2000 – 2002		Unaudited Tax Years 2003 – 2006		Total
Replacement Leases (SILO)	$	44	$	19	$	23	$	86
Lease/Leaseback (LILO)		558		562		6		1,126
Service Contract (SILO)		—		126		199		325
	$	602	$	707	$	228	$	1,537


		Page
Current Developments		40
Southern California Edison Company		44
Edison Mission Group		56
Edison International (Parent)		75
Results of Operations and Historical Cash Flow Analysis		76
New Accounting Pronouncements		86
Commitments, Guarantees and Indemnities		87
Other Developments		89


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


	September 30, 2007		December 31, 2006
In millions	Assets	Liabilities	Assets	Liabilities
Energy options	$ —	$ 46	$ —	$ 10
FTRs	53	—	—	—
Forward physicals (power) and tolling arrangements	—	8	—	1
Gas options, swaps and forward arrangements	—	44	—	101
Total	$ 53	$ 98	$ —	$ 112


In millions	October through December 2007		2008		2009

Illinois Plants
Plant capital expenditures	$	12	$	45	$	26
Environmental expenditures		19		39		66

Homer City Facilities
Plant capital expenditures		4		26		20
Environmental expenditures		1		9		15

Wind and Thermal Projects
Projects under construction		163		165		5
Turbine commitments		123		518		416

Corporate Capital Expenditures		3		19		14
Total	$	325	$	821	$	562


Subsidiary	Financial Ratio	Covenant	Actual
Midwest Generation (Illinois plants)	Debt to Capitalization Ratio	Less than or equal to 0.60 to 1	0.23 to 1

EME Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.81 to 1


	24-Hour Northern Illinois Hub Historical Energy Prices⁽¹⁾
	2007		2006
January	$	35.75	$	42.27
February		56.64		42.66
March		42.04		42.50
April		48.91		43.16
May		44.49		39.96
June		39.76		34.80
July		43.40		51.82
August		57.97		54.76
September		39.68		31.87
Nine-Month Average	$	45.40	$	42.64


	24-Hour Northern Illinois Hub Forward Energy Prices⁽¹⁾
2007
October	$	37.76
November		36.60
December		42.36

2008 Calendar “strip”⁽²⁾	$	46.80
2009 Calendar “strip”⁽²⁾	$	48.70


	Historical Energy Prices⁽¹⁾ 24-Hour PJM
	Homer City				West Hub
	2007		2006		2007		2006
January	$	40.30	$	48.67	$	44.63	$	54.57
February		64.27		49.54		73.93		56.39
March		55.00		53.26		61.02		58.30
April		52.42		48.50		58.74		49.92
May		48.12		44.71		53.89		48.55
June		45.88		38.78		60.19		45.78
July		48.23		53.68		58.89		63.47
August		55.44		58.60		71.00		76.57
September		48.90		33.26		60.14		34.40
Nine-Month Average	$	50.95	$	47.67	$	60.27	$	54.22


	24-Hour PJM West Hub Forward Energy Prices⁽¹⁾
2007
October	$	46.39
November		45.74
December		51.31

2008 Calendar “strip”⁽²⁾	$	61.71
2009 Calendar “strip”⁽²⁾	$	64.53


		October 1, 2007 to May 31, 2008				June 1, 2008 to May 31, 2009
	Midwest Generation		EME Homer City		Midwest Generation		EME Homer City
Fixed Price Capacity Sales
Through RPM Auction, Net
MW		2,596		786		3,283		820
Price per MW-day	$	40.80	$	40.80	$	111.92	$	111.92
Non-unit Specific Capacity Sale
MW		500		—		880		—
Price per MW-day	$	21.31		—	$	64.35		—

Variable Capacity Sales
MW		—		885		—		891
Expected Price per MW-day⁽¹⁾		—	$	66.72		—	$	72.11


	Amount of Coal Under Contract in Millions of Tons⁽¹⁾
	October through December 2007	2008	2009	2010
Illinois Plants	5.0	14.6	11.7	11.7
Homer City facilities	1.4	4.4	3.5	0.2


In millions	September 30, 2007		December 31, 2006
Commodity price:
Electricity	$	(35)	$	184


In millions	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	(35	)	$	(23	)	$	(12	)	$	—	$	—


In millions
Fair value of trading contracts at January 1, 2007	$	111
Net gains from energy trading activities		108
Amount realized from energy trading activities		(97	)
Other changes in fair value		(4	)
Fair value of trading contracts at September 30, 2007	$	118


In millions	Total Fair Value		Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	36	$	31	$	5	$	—	$	—
Prices based on models and other valuation methods		82		4		14		21		43
Total	$	118	$	35	$	19	$	21	$	43


In millions	September 30, 2007
S&P Credit Rating
A or higher	$	44
A-		42
BBB+		54
BBB		26
BBB-		3
Below investment grade		—
Total	$	169


In millions	Earnings (Loss)
Three-Month Period Ended September 30,	2007			2006
Earnings (Loss) from Continuing Operations:
SCE	$	262		$	263
EMG		207			204
Edison International (parent) and other		(4	)		(7	)
Edison International Consolidated Earnings from Continuing Operations		465			460
Loss from Discontinued Operations		(4	)		(2	)
Edison International Consolidated	$	461		$	458

In millions, except per-share amounts	Earnings (Loss)
Nine-Month Period Ended September 30,	2007			2006
Earnings (Loss) from Continuing Operations:
SCE	$	587		$	618
EMG		313			221
Edison International (parent) and other		(14	)		(22	)
Edison International Consolidated Earnings from Continuing Operations		886			817
Earnings from Discontinued Operations		1			75
Cumulative Effect of Accounting Change		—			1
Edison International Consolidated	$	887		$	893


In millions	Three Months Ended September 30, 2007 vs. 2006			Nine Months Ended September 30, 2007 vs. 2006
Electric utility revenue
Rate changes and impact of tiered rate structure (including unbilled)	$	(434	)	$	(468	)
Sales volume changes (including unbilled)		26			103
Balancing account over/under collections		468			369
Sales for resale		63			74
SCE’s VIEs		(9	)		(7	)
Other (including inter company transactions)		20			6
Total	$	134		$	77


	Three Months Ended September 30,				Nine Months Ended September 30,
In millions	2007		2006		2007		2006
SCE	$	310	$	286	$	904	$	836
EMG		192		200		521		490
Edison International Consolidated	$	502	$	486	$	1,425	$	1,326


	Three Months Ended September 30,					Nine Months Ended September 30,
In millions	2007		2006			2007			2006
Purchased-power from bilateral contracts, QFs, ISO, FTRs and exchange energy	$	1,153	$	1,028		$	2,356		$	2,351
Unrealized (gains) losses on economic hedging activities - net		67		9			(23	)		351
Realized losses on economic hedging activities - net		58		114			111			279
Energy settlements and refunds		6		(115	)		(13	)		(162	)
Total purchased-power expense	$	1,284	$	1,036		$	2,431		$	2,819


	Three Months Ended September 30,				Nine Months Ended September 30,
In millions	2007		2006		2007		2006
SCE	$	780	$	715	$	2,152	$	2,074
EMG		226		186		716		628
Edison International (parent) and other		7		8		25		25
Edison International Consolidated	$	1,013	$	909	$	2,893	$	2,727