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 months ended March 31, 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.

Certain prior-period amounts were reclassified to conform to the March 31, 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, that 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. Further, the 1998 and 1999 options did not earn dividend equivalents until 2006, when performance criteria were triggered.

Basic EPS is computed by dividing net income allocated for common stock by the weighted-average number of common shares outstanding. Net income allocated for common stock was $328 million and $255 million for the three months ended March 31, 2007 and 2006, respectively. In determining net income allocated for common stock, dividends on preferred and preference stock of utility have been deducted.

For the diluted EPS calculation, dilutive securities (stock-based compensation awards) are added to the weighted-average shares and net income is adjusted for dividend equivalents on dilutive securities. Stock options with exercise prices greater than or equal to the market price are not included in the dilutive securities calculation. Dilutive securities are excluded from the diluted EPS calculation for items with a net loss due to their antidilutive effect.

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. Based on the current status of discussions with tax authorities related to open tax years under audit and other information currently available, implementation of FIN 48 resulted in a cumulative-effect adjustment that increased retained earnings by $250 million. Edison International will continue to monitor and assess new income tax developments including the IRS’ challenge of the sale/leaseback and lease/leaseback transactions discussed in “Federal and State Income Taxes” in Note 6.

In July 2006, the FASB issued an FSP on accounting for a change or projected 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.

remeasurement to fair value would be reported as a cumulative-effect adjustment to the opening balance of retained earnings. Edison International will adopt SFAS No. 159 on January 1, 2008. Edison International is currently evaluating the impact of adopting SFAS No. 159 on its consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. 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. SCE’s franchise fees billed to customers and recorded as electric utility revenue were $23 million and $20 million for the three months ended March 31, 2007 and 2006, respectively. 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.

Edison International’s short-term investments are primarily composed of short-term investments at EME. At March 31, 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 short-term investments, which all mature within one year, consisted of the following:

Stock, 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, restricted stock units, and Director grants. 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. 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 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. The following is a summary of purchased-power expense:

The 2007 net unrealized gains were primarily due to higher forward natural gas prices in the first quarter 2007, compared to the same period in 2006.

SCE’s short-term debt is generally used to finance fuel inventories, balancing account undercollections and general, temporary cash requirements. At March 31, 2007, the outstanding short-term debt and weighted-average interest rate was $120 million at 5.37%. SCE’s short-term debt is supported by a $2.5 billion credit line of which $2.1 billion was available as of March 31, 2007.

Edison International’s composite federal and state statutory 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 28% for the three months ended March 31, 2007, as compared to 38% for the respective period in 2006. The decreased effective tax rate was primarily caused by reductions made to the income tax reserve at SCE in 2007 to reflect progress in an administrative appeal process with the IRS related to the income tax treatment of costs associated with environmental remediation.

The total amount of unrecognized tax benefits as of the date of adoption of FIN 48 was $201 million. The total amount of unrecognized tax benefits as of the date of adoption that, if recognized, would affect the effective tax rate was $138 million. The total amount of accrued interest and penalties was $119 million as of the date of adoption. Edison International reduced its accrued liability for interest and penalties during the first quarter of 2007 to reflect progress in settlement negotiations with the IRS. The total benefit recognized in income tax

expense for the three months ended March 31, 2007 was $33 million. The total amount of interest expense and penalties recognized in income tax expense was $16 million for the three months ended March 31, 2006.

Edison International remains subject to examination by the IRS from 1994 – present. In addition, the statute of limitations remains open from 1986 – 1993 on selected affirmative issues. Edison International remains subject to examination by the California Franchise Tax Board from 2003 – present. In addition, 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. In April 2007, Edison International received a Notice of Proposed Adjustment from the California Franchise Tax Board for tax years 2001 and 2002 asserting a net deficiency in state taxes. Edison International plans to protest these deficiency assessments and, except for an estimated second quarter 2007 reduction in tax reserves of approximately $15 million, Edison International cannot reasonably predict the outcome or timing of any resolution or amount of any additional potential adjustment to tax reserves. In addition, Edison International continues its efforts to resolve open tax issues with the IRS and State authorities. The timing for resolving these open tax positions is subject to uncertainty, but it is reasonably possible that some portion of these open tax positions could be resolved in the next twelve 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 March 31, 2007, $52 million in contributions have been made related to fiscal year 2006. 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 March 31, 2007, $5 million in contributions have

been made related to fiscal year 2006. 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 $7 million and $11 million for the three months ended March 31, 2007 and 2006, respectively. The income tax benefit recognized in the consolidated statements of income was $3 million and $4 million for the three months ended March 31, 2007 and 2006, respectively. Total stock-based compensation cost capitalized was $1 million for each of the three months ended March 31, 2007 and 2006.

The amount of cash used to settle stock options exercised was $86 million and $44 million for the three months ended March 31, 2007 and 2006, respectively. Cash received from options exercised was $39 million and $21 million for the three months ended March 31, 2007 and 2006, respectively. The estimated tax benefit from options exercised was $18 million and $9 million for the three months ended March 31, 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 a new operating lease for power contracts during the first three months of 2007. SCE’s additional operating lease commitments for this new power contract are estimated to be $68 million for 2008, $114 million for 2009, $114 million for 2010, and $114 million for 2011.

Midwest Generation has entered into additional fuel purchase commitments during the first three months of 2007. These additional commitments are currently estimated to be $106 million in 2008, $74 million in 2009, and $77 million in 2010.

SCE entered into service contracts associated with uranium enrichment and fuel fabrication during the first three months of 2007. SCE’s additional nuclear fuel commitments for the remainder of 2007 are estimated to be $70 million.

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 commitments under this agreement 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 three months of 2007 relates to additional volumes of fuel purchases using the terms of existing transportation agreements. These commitments are currently estimated to be $110 million for 2008, $75 million for 2009, and $76 million for 2010.

At March 31, 2007, EME’s subsidiaries had firm commitments to spend approximately $133 million during the remainder of 2007 and $25 million in 2008 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 system and environmental improvements. These expenditures are planned to be financed by cash on hand, cash generated from operations or existing subsidiary credit agreements.

At March 31, 2007, EME had entered into agreements with vendors securing 357 wind turbines (734 MW) with remaining commitments of $508 million in 2007 and $176 million in 2008. EME has the option to purchase an additional 83 wind turbines (199 MW) for delivery in 2009. In addition, EME had entered into an agreement for the purchase of five gas turbines and related equipment for an aggregate purchase price of approximately $145 million with remaining commitments of $53 million in 2007 and $3 million in 2008. In February 2007, EME was advised that it was an unsuccessful bidder in the request for offers conducted by SCE for the supply of generation capacity. EME plans to use the turbines which it had purchased and reserved for this bid for other generation supply opportunities. At March 31, 2007, EME had recorded turbine deposits of $210 million included in other long-term assets in Edison International’s consolidated balance sheet.

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 will continue 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 176 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at March 31, 2007. Midwest Generation had recorded a $64 million liability at March 31, 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 March 31, 2007, EME had recorded a liability of $97 million, respectively, 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 March 31, 2007, if payment were required, would be $92 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.

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.

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

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 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 a 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 of the Northern District of Illinois, Eastern Division.

On March 30, 2007, David Schafer, Tim Perry, Pat Martin and Michael Murray, individually and on behalf of a 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.

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 March 31, 2007, Edison International’s recorded estimated minimum liability to remediate its 37 identified sites at SCE (23 sites) and EME (14 sites related to Midwest Generation) is $79 million, $76 million of which is 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 $125 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 32 immaterial sites whose total liability ranges from $3 million (the recorded minimum liability) to $8 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $29 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $75 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 twelve months ended March 31, 2007 were $16 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.

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

The following table summarizes estimated federal and state income taxes deferred from these leases as of March 31, 2007. Repayment of these deferred taxes would be accelerated if the IRS prevails:

As of March 31, 2007, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $419 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 recently decided against the taxpayer on summary judgment in the Federal District Court in North Carolina. That taxpayer has announced its intention to appeal that decision to the Fourth Circuit Court of Appeals.

Edison International expects to file a refund claim for any taxes and penalties paid pursuant to the administrative appeals settlement of the 1994 – 1996 tax years related to assessed tax deficiencies and penalties 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. While Edison International intends to defend its tax return position with respect to this transaction, the tax benefits relating to this transaction have been valued at an amount equal to the settlement offer made by the Internal Revenue Service pursuant to FIN 48.

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.

At the end of 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 FERC’s rules with respect to certain bidding practices employed by EMMT. EMMT is engaged in discussions with the staff to explore the possibility of resolution of this matter. Should a formal proceeding be commenced, EMMT will be entitled to contest any alleged violations before the FERC and an appropriate court. EME believes that EMMT has complied with the FERC’s rules and intends to contest vigorously any allegation of violation. EME cannot predict at this time the outcome of this matter or estimate the possible liability should the outcome be adverse.

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 2000 – 2001 California energy crisis or who benefited from the manipulation by receiving inflated market prices. SCE is required to refund to customers 90% of any refunds actually realized by SCE, net of litigation costs, and 10% will be retained by SCE as a shareholder incentive.

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

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

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

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 employees 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.

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

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

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

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

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

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

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. The order directed the ISO to shift the charges from scheduling coordinators in the affected zone to the responsible participating transmission owner, SCE. The potential cost to SCE, net of amounts SCE expects to receive through the PX, SCE’s scheduling coordinator at the time, is estimated to be approximately $20 million to $25 million, including interest. On 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. SCE believes that the most recent FERC order correctly allocates responsibility for these ISO charges. However, SCE cannot provide assurance as to the final outcome of the Cities request for 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 has reported a profit in 2006, it has 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 March 31, 2007, American Airlines was current in its lease payments to Edison Capital.

Edison Capital also has a net leveraged lease investment of $45 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 March 31, 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 “SCE: Regulatory Matters—Current Regulatory Developments—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.

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

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

Pursuant to a joint request of the parties, the District Court granted a stay of the action on October 5, 2004 to allow the parties to attempt to negotiate a resolution of the issues associated with Mohave with the assistance of a facilitator. An initial organizational session was held with the facilitator on October 14, 2004 and negotiations are on-going. On July 28, 2005, the District Court issued an order removing the case from its active calendar, subject to reinstatement at the request of any party. On April 30, 2007, the District Court 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 light of the duration of the stay.

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

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.

a later time through actual deliveries of eligible renewable energy and made an accounting determination that defines the annual targets for each year of the renewable portfolio standards program. Based on terms of the controlling California statute, in March 2007, SCE successfully challenged the CPUC’s accounting determination of SCE’s annual targets. This change is expected to enable SCE to meet its target for 2007 and possibly later years.

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 will be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance filing. Under the CPUC’s current rules, the maximum penalty for failing to achieve renewable procurement targets is $25 million per year. SCE cannot predict whether it will be assessed penalties.

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. As a result, SCE could be required to refund all or part of the amounts collected from the DWP under the tariff. As of March 31, 2007, SCE has an accrued liability of $42 million for the potential refunds. In September 2006, SCE and DWP entered into a term sheet that would settle this dispute, among others surrounding the Exchange Agreement. If the settlement is effectuated, SCE would refund to DWP the scheduling coordinator charges collected, with an offset for losses, subject to being able to recover the scheduling coordinator charges from all transmission grid customers through another regulatory mechanism. The parties are currently negotiating the exact terms of the settlement which would be subject to FERC and ISO approval.

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its obligation to begin acceptance of spent nuclear fuel not later than January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to 0.1¢-per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE’s failure

to meet its obligation to begin accepting spent nuclear fuel from San Onofre. The case was stayed through April 7, 2006, when SCE and the DOE filed a Joint Status Report in which SCE sought to lift the stay and the government opposed lifting the stay. On June 5, 2006, the Court of Federal Claims lifted the stay on SCE’s case and established a discovery schedule. A Joint Status Report is due on September 7, 2007, regarding further proceedings in this case and presumably including establishing a trial date.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel storage installation where all of Unit 1’s spent fuel located at San Onofre is stored. There is now sufficient space in the Unit 2 and 3 spent fuel pools to meet plant requirements through mid-2007 and mid-2008, respectively. In order to maintain a full core off-load capability, SCE began moving Unit 2 spent fuel into the independent spent fuel storage installation in late February 2007.

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 after 2008 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 gains/losses on cash flow hedges, net of tax, at March 31, 2007, include $43 million of unrealized losses on commodity hedges related to EME’s Homer City and Midwest Generation 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 first quarter of 2007 resulted from an increase in market prices for power.

As EME’s hedged positions for continuing operations are realized, approximately $29 million (after tax) of the net unrealized losses on cash flow hedges at March 31, 2007 are expected to be reclassified into earnings during the next 12 months. EME expects that reclassification of the net unrealized losses will offset 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 an EME cash flow hedge is designated is through December 31, 2009.

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. EME recorded net losses of approximately $1 million and $11 million during the first quarters of 2007 and 2006, respectively, representing the amount of cash flow hedges’ ineffectiveness for continuing operations, reflected in nonutility power generation revenue on Edison International’s consolidated statements of income.

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

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 deferred FTR costs are recognized as FTRs are used or expire during the period April 2007 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.

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 remaining 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 and £4 million (approximately $8 million) in January 2007. The after-tax income attributable to the Lakeland project was $5 million and $73 million for the first quarters of 2007 and 2006, respectively. Beginning in 2002, EME reported the Lakeland project among 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.

There was no revenue for either of the quarters ended March 31, 2007 or 2006. For the three months ended March 31, 2007 and 2006, pre-tax income was $6 million and $111 million, respectively.

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.

EME used the 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 $999.8 million of Midwest Generation’s 8.75% second priority senior secured notes due 2034, to repay the outstanding amount ($327.8 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 approximately $795.7 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. MEHC expects to record a total pre-tax loss of approximately $242 million (approximately $148 million after tax) on early extinguishment of debt during the second quarter of 2007.

In addition, on May 7, 2007, EME amended its existing $500 million secured credit facility, increasing the total borrowings available thereunder to $600 million.

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-month period ended March 31, 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-month period ended March 31, 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, MEHC and Edison Capital, a provider of capital and financial services. MEHC is the holding company for its wholly owned subsidiary, EME, which is engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities.

In this MD&A, except when stated to the contrary, references to each of Edison International, SCE, EMG, MEHC, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to Edison International (parent) or parent company and MEHC (parent) mean Edison International or MEHC 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 May 8, 2007, SCE filed its 2008 cost of capital application requesting a rate-making capital structure of 43% long-term debt, 9% preferred equity and 48% common equity. In addition, SCE is seeking a cost of long-term debt of 6.20%, cost of preferred equity of 5.98% and a return on common equity of 11.80%.

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. The proceeds were used, together with cash on hand, to:

MEHC intends to redeem the remaining 13.5% senior secured notes due 2008 that were not tendered, subject to market conditions. MEHC expects to record a total pre-tax loss of approximately $242 million (approximately $148 million after tax) on early extinguishment of debt during the second quarter of 2007. See “EMG: Liquidity—Financing Activities.”

In addition to the above-mentioned debt refinancing, on May 7, 2007, EME amended its existing $500 million secured credit facility, increasing the total borrowings available thereunder to $600 million, and Midwest Generation plans to replace its existing $500 million senior secured working capital facility with a new senior secured working capital facility with a longer maturity date and less restrictive covenants. Midwest Generation intends to use its new secured working capital facility to provide credit support for its hedging activities, including through the option to extend power hedges by granting the counterparties a first lien to secure such hedges, and general working capital purposes.

The above-mentioned refinancing activities eliminate MEHC’s reliance on dividends from EME and the restrictive covenants set forth in the indenture related to the 13.5% senior secured notes due 2008, improve MEHC and EME’s overall liquidity, extend the maturity dates of indebtedness, reduce annual interest costs, improve operating flexibility, and improve EME’s ability to capitalize on growth opportunities.

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

In April 2007, PJM completed the first capacity auction under the PJM Reliability Pricing Model. EME participated in the auction for the period June 1, 2007 through May 31, 2008. After accounting for previous forward sales of capacity, EMMT sold net 3,013 MW of capacity from the Illinois plants and net 886 MW of capacity from the Homer City facilities. The Illinois plants and the Homer City facilities are located in the “Rest of Market” area which had a clearing price of $40.80 per MW-day.

As of March 31, 2007, SCE had cash and equivalents of $85 million ($80 million of which was held by SCE’s consolidated VIEs). As of March 31, 2007, long-term debt, including current maturities of long-term debt, was $5.5 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 March 31, 2007, the credit facility supported $304 million in letters of credit and $120 million in commercial paper leaving $2.1 billion available for liquidity purposes.

SCE’s estimated cash outflows during the twelve-month period following March 31, 2007 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, when necessary. Projected capital expenditures are expected to be financed through operating cash flows and the issuance of short-term and long-term debt and preferred equity.

SCE’s liquidity may be affected by, among other things, matters described in “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 its distribution and transmission infrastructure, and to construct and replace major components of generation assets. On February 22, 2007, the Finance Committee of the Board of Directors approved SCE’s 2007 through 2011 capital investment plan which includes total capital spending of up to $17.3 billion. During the first quarter of 2007, SCE spent $495 million in capital expenditures related to its 2007 capital plan.

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 March 31, 2007, SCE’s 13-month weighted-average common equity component of total capitalization was 49.48%. At March 31, 2007, SCE had the capacity to pay $171 million in additional dividends based on the 13-month weighted-average method. However, based on recorded March 31, 2007 balances, SCE’s common equity to total capitalization ratio (as adjusted for rate-making purposes) was 50.18%. SCE had the capacity to pay $252 million of additional dividends to Edison International based on March 31, 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 March 31, 2007, SCE’s debt to total capitalization ratio was 0.45 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 March 31, 2007, SCE had a net deposit of $300 million (consisting of $36 million in cash and reflected in “Margin and collateral deposits” on the consolidated balance sheet and $264 million in letters of credit) with counterparties. In addition, SCE has deposited $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 system average rate was 14.5¢ per-kWh (including 3.1¢ per-kWh related to CDWR which is not recognized as revenue by SCE). On February 14, 2007, SCE’s system average rate decreased to 13.9¢-per-kWh (including 3.0¢ per-kWh related to CDWR) mainly as the result of estimated lower natural gas prices in 2007, as well as the refund of overcollections in the ERRA balancing account that occurred in 2006 from lower than expected natural gas prices and higher than expected summer 2006 kWh sales (see “—Energy Resource Recovery Account Proceedings” below). In addition, the rate change incorporates the collection of the residential rate increase deferral discussed in the year-ended 2006 MD&A under the heading “Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates.”

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings” in the year-ended 2006 MD&A, the ERRA is the balancing account mechanism

to track and recover SCE’s fuel and procurement-related costs. At December 31, 2006, the ERRA was overcollected by $526 million, which was 13.2% of SCE’s prior year’s generation revenue. On January 25, 2007, the CPUC approved SCE’s request to reduce the 2007 ERRA revenue requirement by $630 million. The CPUC also authorized SCE to consolidate the decreased ERRA revenue requirement with the authorized revenue requirement changes in other SCE proceedings resulting in lower rate levels implemented in February 2007. See “—Impact of Regulatory Matters on Customer Rates” above for further discussion. At March 31, 2007 the ERRA was overcollected by $605 million. The ERRA overcollection increased since December 31, 2006 mainly as a result of lower procurement costs recorded during the first quarter of 2007 compared to forecast costs incorporated into rates; however SCE still anticipates this overcollection will decrease during 2007, based on the reduced ERRA revenue requirement approved by the CPUC on January 25, 2007.

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—ISO Disputed Charges” in the year-ended 2006 MD&A, on April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. On March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. SCE believes that the most recent FERC order correctly allocates responsibility for these ISO charges. However, SCE cannot provide assurance as to the final outcome of the Cities request for 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 “Regulatory Matters—Current Regulatory Developments—Peaker Plant Generation Projects” in the year-ended 2006 MD&A, 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 continues to pursue the construction of five combustion turbine peaker plants, each with a capacity of approximately 45 MW. As of April 4, 2007, SCE had received construction permits for four of the five projects. SCE cannot predict when it will receive the permit for the fifth project and cannot estimate the impact that this delay will have on the project’s construction schedule. SCE believes that construction of all five peakers will help meet electric reliability needs, notwithstanding the delay encountered by one of the projects. SCE has revised its initial budget from $250 million to approximately $275 million for these projects. SCE expects to fully recover its costs from these projects, but cannot predict the outcome of regulatory proceedings. As of March 31, 2007 SCE had spent or firmly committed approximately $133 million.

On October 19, 2006, the CPUC issued a decision that, among other things, implemented a “cumulative deficit banking” feature which would carry forward and accumulate annual deficits until the deficit has been satisfied at a later time through actual deliveries of eligible renewable energy and made an accounting determination that defines the annual targets for each year of the renewable portfolio standards program. Based on terms of the

controlling California statute, in March 2007, SCE successfully challenged the CPUC’s accounting determination of SCE’s annual targets. This change is expected to enable SCE to meet its target for 2007 and possibly later years.

During the course of the refund proceedings, the FERC ruled that governmental power sellers, like private generators and marketers that sold into the California market, should refund the excessive prices they received during the crisis period. However, on September 21, 2005, the Ninth Circuit ruled that the FERC does not have authority directly to enforce its refund orders against governmental power sellers. The Court, however, clarified that its decision does not preclude SCE or other parties from pursuing civil claims against the governmental power sellers. On March 16, 2006, SCE, PG&E and the California Electricity Oversight Board jointly filed suit in federal court against several governmental power sellers, seeking damages based on the reduced prices set by the FERC for transactions during the crisis period. In March 2007, the federal court dismissed this suit concluding that the claims should have been filed in state court. SCE, along with PG&E, the Oversight Board and SDG&E, re-filed on April 9, 2007 in the Los Angeles Superior Court. In addition, on March 12, 2007, SCE, PG&E and the Oversight Board filed a similar group of claims in the U.S. Court of Federal Claims against two federal agencies that sold power into California during the energy crisis. SCE cannot predict whether it may be able to recover any damages from governmental power sellers as a result of these suits.

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

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

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.

SCE recorded net unrealized gains of $134 million for the first quarter of 2007, compared to net unrealized losses of $334 million for the first quarter of 2006. The 2007 net unrealized gains were primarily due to higher forward natural gas prices in the first quarter of 2007 compared to the same period in 2006.

At March 31, 2007, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.7 billion, and EME had a total of $952 million of available borrowing capacity under its $500 million corporate credit facility and a $500 million working capital facility at Midwest Generation. EME’s consolidated debt at March 31, 2007 was $3.1 billion. In addition, EME’s subsidiaries had $4.2 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 28 years.

Edison Capital’s main sources of liquidity are tax-allocation payments from Edison International, distributions from its global infrastructure fund investments and lease rents. As of March 31, 2007, Edison Capital had unrestricted cash and cash equivalents of $365 million and long-term debt, including current maturities, of $127 million.

At March 31, 2007, the three-year estimated capital expenditures 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 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 three years. In addition to the capital expenditures to purchase turbines set forth in the above table, EME has entered into a letter of intent to purchase 300 turbines (totaling 630 MW) for delivery in 2008 and 2009. The purchase of these turbines is subject to completion of a definitive turbine purchase agreement. EME has also made a reservation fee payment of $8 million for 83 additional turbines (totaling 199 MW) for 2009 delivery, subject to issuance of a notice to proceed by June 30, 2007. Estimated capital expenditures under these agreements would be approximately $940 million, not including the cost to complete construction, if the maximum number of turbines were purchased.

As of April 30, 2007, EME has a development pipeline of potential wind projects with an installed capacity of approximately 2,700 MWs (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 March 31, 2007, are as follows:

Subsequent to March 31, 2007, the rating agencies affirmed the above–mentioned EME ratings in connection with the financing activities discussed above under “—Financing Activities” and affirmed the rating for the Midwest Generation first priority secured revolving credit facility, except that S&P increased its rating to BB+ from BB.

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 or EME 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. Because the credit ratings of EMMT and EME are below investment grade, EME has historically 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 March 31, 2007, EMMT had deposited $157 million in cash with brokers in margin accounts in

support of futures contracts and had deposited $62 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $2 million in support of commodity contracts at March 31, 2007.

Future cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2007, if wholesale energy prices increase or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of March 31, 2007 could increase by approximately $410 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 March 31, 2007, Midwest Generation had available $495 million of borrowing capacity under this credit facility. As of March 31, 2007, Midwest Generation had $65 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and a $500 million working capital facility to provide credit support to subsidiaries. See “—EME’s Liquidity as a Holding Company” for further discussion.

At March 31, 2007, EME had corporate cash and cash equivalents and short-term investments of $1.3 billion to meet liquidity needs. See “—Liquidity.” Cash distributions from EME’s subsidiaries and partnership investments and unused capacity under its corporate credit facility represent EME’s major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME’s subsidiaries may be affected by many factors beyond its control. See “—Dividend Restrictions in Major Financings.”

The following table is presented as an aid in understanding the cash flow of EME’s continuing operations and its various subsidiary holding companies which depend on distributions from subsidiaries and affiliates to fund general and administrative costs and debt service costs of recourse debt.

MEHC (parent), 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 right of MEHC (parent), EME and Edison Capital to receive and the amount of and timing of tax-allocation payments are dependent on the

inclusion of MEHC (parent), EME and Edison Capital, respectively, 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. MEHC (parent), 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 MEHC (parent)’s, 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, MEHC (parent), EME and Edison Capital are obligated during periods they generate taxable income to make payments under the tax-allocation agreements.

Each of EME’s direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME’s subsidiaries are not available to satisfy EME’s obligations or 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 EME or to its subsidiary holding companies.

Set forth below are key ratios of EME’s principal subsidiaries required by financing arrangements for the twelve months ended March 31, 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 to Edison International (parent) is restricted by debt covenants (see “Edison International (Parent): Liquidity” for further discussion). As of March 31, 2007, Edison Capital complied with its debt covenants.

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

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 a 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.

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 its 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 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 three 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 March 31, 2007:

The following table summarizes Midwest Generation’s hedge position (primarily based on prices at the Northern Illinois Hub) at March 31, 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 three 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 March 31, 2007:

The average price/MWh for 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.

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. 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 three months ended March 31, 2007 and 2006, 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 11%. The monthly average difference during the 12 months ended March 31, 2007 ranged from 3% to 23%. 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.

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 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 March 31, 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 quarter 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 $44.50 per ton at March 23, 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. Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO₂ per MMBtu sulfur content), which is purchased for the Illinois plants decreased during the first quarter of 2007 from 2006 year-end prices due to continuing high stockpiles and oversupply of the market. The price of PRB coal decreased from $9.90 per ton at December 15, 2006 to $8.55 per ton at March 23, 2007, as reported by the Energy Information Administration.

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 $478 per ton during the first quarter 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 $435 per ton as of March 31, 2007.

For a discussion of environmental regulations related to emissions, refer to “Other Developments” 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 “Critical Accounting Estimates—Derivative Financial Instruments and Hedging Activities” 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 revenue. 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 first quarters of 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 decrease in fair value of electricity contracts at March 31, 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 March 31, 2007, which is the valuation date. 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 March 31, 2007:

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

The change in the fair value of trading contracts for the quarter ended March 31, 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 March 31, 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 March 31, 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 48% of EME’s consolidated operating revenue for the three months ended March 31, 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 March 31, 2007, EME’s account receivable due from PJM was $89 million. For the three months ended March 31, 2007, a second customer accounted for 14% of EME’s consolidated operating revenue.

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 18% of EME’s consolidated operating revenue during the three months ended March 31, 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 March 31, 2007, EME’s account receivable due from Commonwealth Edison was $36 million. Commonwealth Edison has stated that it would face possible bankruptcy if an electric rate freeze, which expired January 1, 2007, was re-introduced through legislation which is currently pending in the Illinois General Assembly. In addition, the Illinois Attorney General and other parties have appeals pending before the Illinois Supreme Court pertaining to the Illinois Commerce Commission orders which authorized Commonwealth Edison and Ameren to procure power through a reverse auction process. EME is unable to predict the outcome of the appeals or whether legislation or other policy changes affecting utility rates or procurement practices will be enacted, and, if so, what effect these developments may have on Commonwealth Edison’s performance under the load requirements services contracts.

Edison Capital’s investments may be affected by the financial condition of other parties, the performance of the asset, economic conditions and other business and legal factors. Edison Capital generally does not control operations or management of the projects in which it invests and must rely on the skill, experience and performance of third party project operators or managers. These third parties may experience financial difficulties or otherwise become unable or unwilling to perform their obligations. Edison Capital’s investments generally depend upon the operating results of a project with a single asset. These results may be affected by general market conditions, equipment or process failures, disruptions in important fuel supplies or prices, or another party’s failure to perform material contract obligations, and regulatory actions affecting utilities purchasing power from the leased assets. Edison Capital has taken steps to mitigate these risks in the structure of each project through contract requirements, warranties, insurance, collateral rights and default remedies, but such measures may not be adequate to assure full performance. In the event of default, lenders with a security interest in the asset may exercise remedies that could lead to a loss of some or all of Edison Capital’s investment in that asset.

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 MEHC’s consolidated long-term obligations (including current portion) was $4.3 billion at March 31, 2007, compared to the carrying value of $3.9 billion. The fair market value of MEHC’s parent only total long-term obligations was $0.9 million at March 31, 2007, compared to the carrying value of $0.8 million.

EME is exposed to foreign currency risk associated with the purchase of certain turbines in which a portion of the purchase price is denominated in Japanese yen. Under the terms of the related agreement, EME has the option of fixing the foreign currency rate at the time of a notice to proceed which is required by June 30, 2007. See “Commitments, Guarantees and Indemnities—Turbine Commitments.”

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 March 31, 2007, Edison Capital had investments in Latin America, Asia and Emerging Europe of $23 million, $14 million and $31 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 March 31, 2007, Edison International had no debt outstanding (excluding intercompany related debt).

Edison International (parent)’s cash requirements for the 12-month period following March 31, 2007 primarily consist of:

Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand, borrowings, when necessary, and dividends from its subsidiaries. At March 31, 2007, Edison International (parent) had approximately $35 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 March 31, 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. During the first quarter 2007, SCE made dividend payments to Edison International of $60 million in January 2007, and $25 million in April 2007. On April 26, 2007, the Board of Directors of SCE declared a $25 million dividend to be paid to Edison International.

MEHC’s certificate of incorporation contains restrictions on MEHC’s ability to declare or pay dividends or distributions (other than dividends payable solely in MEHC’s common stock). These restrictions require the unanimous approval of MEHC’s Board of Directors, including its independent director, before it can declare or pay dividends or distributions, as long as any indebtedness is outstanding under the indenture. MEHC’s ability to pay dividends is dependent on EME’s ability to pay dividends to MEHC (parent). MEHC has not declared or made dividend payments to Edison International in 2007. EME’s subsidiaries have certain dividend restrictions as discussed in the “EMG Liquidity—Dividend Restrictions in Major Financings” section.

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 March 31, 2007.

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-month periods ended March 31, 2007 and 2006, and the relative contributions by its subsidiaries.

Edison International’s first quarter 2007 earnings from continuing operations were $330 million, or $1.00 per basic common share, compared with earnings of $184 million, or 56¢ per basic common share in 2006.

SCE’s first quarter 2007 earnings from continuing operations were $180 million, compared with $121 million in the first quarter 2006. The increase was mainly due to earnings of $31 million reflecting progress in an administrative appeal process with the IRS related to the income tax treatment of costs associated with environmental remediation. In addition, earnings increased due to the delay in receiving the 2006 GRC decision. When the decision was received in May 2006, SCE was authorized to recover its revenue requirement effective back to January 12, 2006.

EMG’s first quarter 2007 earnings from continuing operations were $155 million, compared with earnings of $73 million in first quarter 2006. EMG’s 2007 increase was primarily due to an increase in wholesale energy margins driven by higher generation and energy prices at both Midwest Generation and Homer City. EMG’s Homer City facilities were impacted by a 2006 transformer outage that lasted during part of the first quarter of last year. In addition, results at Midwest Generation were impacted by mark-to-market losses (after-tax) of $13 million related to non-qualifying hedges under FAS 133 resulting from an increase in forward wholesale power prices.

SCE’s retail sales represented approximately 88% and 85% of electric utility revenue for the quarters ended March 31, 2007 and 2006, respectively. Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is generally significantly higher than other quarters.

Total electric utility revenue increased by $5 million for the three-month period ended 2007 (as shown in the table above). The increase resulting from rate changes was primarily due to the delay in implementing the decreased ERRA revenue requirement resulting in increased rates in the first quarter of 2007 (see “SCE: Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates,” and “—Energy Resource Recovery Account Proceedings” for further discussion of these rate changes). The increase in electric utility revenue resulting from sales volume changes was mainly due to an increase in customer growth. Balancing account over/undercollections represent the difference between recorded retail revenue and authorized retail revenue that is subject to regulatory balancing account mechanisms. Recorded retail revenue exceeded authorized revenue resulting in a revenue deferral of approximately $21 million for the three-month period ended March 31, 2007. For the same period in 2006, authorized revenue exceeded recorded revenue resulting in a revenue recognition of approximately $107 million. Electric utility revenue from sales for resale represents the sale of excess energy. Excess energy from SCE sources which may exist at certain times is resold in the energy markets. Sales for resale revenue decreased due to lower excess energy resulting from higher demand from customer growth in the first quarter of 2007, as compared to the same period in 2006. Revenue from sales for resale is refunded to customers through the ERRA balancing account and does not impact earnings. SCE’s VIE revenue represents the recognition of revenue resulting from the consolidation of four gas-fired power plants where SCE is considered the primary beneficiary. These VIEs affect SCE’s revenue, but do not affect earnings; the decrease in revenue from SCE’s VIEs is primarily due to lower steam and energy prices and for, one of the projects, lower volumes sold in 2007.

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 $587 million and $568 million for the three-month periods ended March 31, 2007 and 2006, respectively.

Nonutility power generation revenue increased $162 million for the three-month period ended March 31, 2007.

Nonutility power generation revenue from EMG’s Illinois plants increased $85 million for the three-month period ended March 31, 2007. The 2007 increase was mainly due to higher energy revenue resulting from higher generation and average realized energy prices as compared to 2006, partially offset by an increase in unrealized losses in 2007 related to hedge contracts. EMG’s Illinois plants recorded unrealized losses of $22 million in the first quarter of 2007, compared to unrealized gains of $10 million for the first quarter of 2006. Unrealized gains (losses)

are primarily due to power contracts entered into to hedge the price risk related to projected sales of power that do not qualify for hedge accounting. During 2007, power prices increased, resulting in mark-to-market losses on these hedges. 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 $75 million for the three-month period ended March 31, 2007. The 2007 increase was primarily attributable to higher generation and average realized energy prices as compared to the same period for 2006, partially offset by lower generation in 2006 as a result of an unplanned outage at Unit 3 (see “Results of Operations and Historical Cash Flow Analysis—Results of Operations—Operating Revenue” in the year-ended 2006 MD&A for further discussion of EMG’s Homer City Unit 3 outage).

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 varies substantially. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall) which reduces generation and increases major maintenance costs which are recorded as an expense when incurred. 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 decreased slightly for the three-month period ended March 31, 2007. The decrease was mainly due to lower fuel expense of approximately $40 million related to SCE’s VIEs driven by lower natural gas prices and lower fuel expense of approximately $5 million at SCE’s Mohave Generating Station resulting from the plant shutdown on December 31, 2005. These decreases were almost entirely offset by an increase of $20 million primarily resulting from newly constructed Mountainview Unit 4 beginning operations mid-January 2006, higher nuclear fuel expense of $15 million resulting primarily from a planned refueling and maintenance outages at SCE’s San Onofre Unit 2 in 2006, and a Department of Energy settlement refund of approximately $10 million related to crude oil overcharges in 2006. The settlement refund was returned to ratepayers through the ERRA mechanism.

EMG’s fuel expense increased $26 million for the three-month period ended March 31, 2007, mainly due to higher generation, partially offset by lower costs of SO₂ emission allowances at EMG’s Homer City facilities.

Purchased-power expense decreased $696 million for the three-month period ended March 31, 2007. The 2007 decrease was mainly due to net unrealized gains on economic hedging activities of $134 million, compared to net unrealized losses on economic hedging activities of $334 million for the same period in 2006 (see “SCE: Market Risk Exposures—Commodity Price Risk” for further discussion). The 2007 net unrealized gains were primarily due to higher forward natural gas prices in the first quarter of 2007, compared to the same period in 2006. In addition, the purchased-power decrease was also due to lower QF purchased power expense of approximately $60 million resulting from lower average spot natural gas prices and lower kWh purchases (as further discussed below), and lower ISO-related purchases of approximately $110 million resulting from lower kWh purchases.

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 will be at a fixed price of 6.15¢-per-kWh, effective May 2007.

Provisions for regulatory adjustment clauses—net increased $652 million for the three-month period ended March 31, 2007. The 2007 increase was mainly due to net unrealized gains on economic hedging activities (mentioned above in purchased-power expense) of approximately $134 million for the three-month period ended March 31, 2007, that, if realized, would be refunded to ratepayers, compared to net unrealized losses on economic hedging activities of $334 million for the three-month period ended March 31, 2006, which, if realized, would be recovered from the ratepayers (see “SCE: Market Risk Exposures—Commodity Price Risk” for further discussion). The increase also reflects higher net overcollections of purchased-power, fuel, and operation and maintenance expense of approximately $185 million resulting from higher rates and lower procurement costs for the three-month period ended March 31, 2007, compared to the same period in 2006.

SCE’s other operation and maintenance expense decreased $13 million for the three-month period ended March 31, 2007. The 2007 decrease was mainly due to higher generation-related costs of approximately $25 million resulting from the planned refueling and maintenance outages at SCE’s San Onofre Units 2 and 3 for the first quarter 2006, and a decrease in must-run and must offer obligation costs of approximately $10 million related to the reliability of the California ISO systems. This decrease was partially offset by higher demand-side management and energy efficiency costs of approximately $25 million (which are recovered through regulatory mechanisms approved by the CPUC).

EMG’s other operation and maintenance expense increased $12 million for the three-month period ended March 31, 2007, mainly due to higher maintenance costs at EMG’s Illinois plants.

SCE’s depreciation, decommissioning and amortization expense increased $23 million for the three-month period ended March 31, 2007. The increase in 2007 was mainly due to an increase in depreciation expense resulting from additions to transmission and distribution assets, as well as an increase from the implementation of the depreciation rates authorized in the 2006 GRC decision, and higher net investment earnings from SCE’s nuclear decommissioning trusts, which, due to its regulatory treatment, are recorded in electric utility revenue and are offset in decommissioning expense. As a result, these investment earnings have no impact on net income.

Equity in income from partnerships and unconsolidated subsidiaries—net increased $13 million for the three-month period ended March 31, 2007. The 2007 increase was mainly due to increased earnings at EMG’s unconsolidated affiliates, Doga and Westside projects, and higher earnings of $5 million from Edison Capital’s global infrastructure funds for the first quarter of 2007, compared to the same period for 2006. Earnings from the Doga project increased $5 million for the first quarter of 2007 primarily due to a planned outage that affected the first quarter of 2006 results. Earnings from the Westside projects increased $4 million due to lower planned maintenance expenses, partially offset by steam and energy prices.

SCE’s other nonoperating income decreased $10 million for the three-month period ended March 31, 2007 mainly due to incentive rewards in 2006 related to the efficient operation of Palo Verde compared to no incentive rewards in 2007 as a result of the incentive program ending in 2006. The incentive reward approved by the CPUC for the efficient operation of Palo Verde was $13 million in the first quarter of 2006. This decrease was partially offset by an increase in allowance for funds used during construction – equity of approximately $5 million resulting from an increase in construction work in progress due to planned capital expenditures (see “SCE: Liquidity—Capital Expenditures” for further discussion).

EMG’s other nonoperating income decreased $15 million for the three-month period ended March 31, 2007, mainly due to 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 $12 million for the three-month period ended March 31, 2007 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 March 31, 2007, compared to the same period in 2006.

EMG’s interest expense—net of amounts capitalized decreased $13 million for the three-month period ended March 31, 2007, mainly due to lower interest rates resulting from EME’s refinancing in June 2006 and an increase in capitalized interest in 2007 related to wind projects under construction.

Edison International’s composite federal and state statutory 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 28% for the three-month period ended March 31, 2007, as compared to 38% for the respective period in 2006. The decreased effective tax rate was primarily caused by reductions made to the income tax reserve at SCE in 2007 to reflect progress in an administrative appeal process with the IRS related to the income tax treatment of costs associated with environmental remediation.

Edison International’s earnings from discontinued operations of $3 million and $73 million in the first quarter of 2007 and 2006, respectively, primarily reflect the receipt of distributions from the U.K. Lakeland project previously owned by EMG.

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 increased $166 million in 2007, compared to 2006. The increase for the three-month period ended March 31, 2007 was due to an increase in cash collected from SCE’s customers due to increased rates (see “SCE: Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates”) which contributed to higher balancing account overcollections in 2007, as compared to the same period in 2006. The 2007 change was also attributable to an increase of $126 million in required margin and collateral deposits in the first quarter of 2007 mainly for EMG’s hedging and trading activities, compared to a decrease of $179 million in the first quarter of 2006. The change resulted from an increase in forward market prices in 2007 compared to 2006. In addition, 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 $66 million in the first quarter 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 and short-term debt payments at SCE and EMG.

Financing activities in the first quarter of 2006 included activities related to the rebalancing of SCE’s capital structure and rate base growth and the reduction of debt at EMG.

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 was $653 million in the first quarter of 2007 and $591 million in the first quarter of 2006. Investing activities in 2007 reflect $560 million in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $20 million for nuclear fuel acquisitions and $131 million in capital expenditures at EMG. Investing activities also include net maturities and sales of marketable securities of $83 million at EMG in the first quarter of 2007, compared to net purchases of marketable securities of $45 million at EMG in the first quarter of 2006. In addition, EME paid $18 million towards the purchase price of the Wildorado wind project, and received proceeds of $43 million from the sale of 25% of its ownership interest in the San Juan Mesa project during the first quarter of 2006.

Net cash used by investing activities in the first quarter of 2006 reflect $494 million in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $17 million for nuclear fuel acquisitions and approximately $4 million related to the Mountainview plant, and $59 million in capital expenditures at EMG.

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 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 will adopt SFAS No. 159 on January 1, 2008. Edison International is currently evaluating the impact of adopting SFAS No. 159 on its consolidated financial statements.

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

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 NO_x emissions, mercury emissions, ozone and fine particulate matter emissions, regional haze, water quality, and climate change, may require significant capital expenditures at these facilities. These laws and regulations will continue to be monitored to assess what implications, if any, they will have on the operation of domestic power plants owned or operated by SCE, 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 April 2, 2007, the United States Supreme Court issued an opinion in Massachusetts et. al. v. Environmental Protection Agency, et. al., ruling that 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 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. Edison International 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.

As of March 31, 2007, Edison International’s recorded estimated minimum liability to remediate the 37 identified sites at SCE (23 sites) and EME (14 sites related to Midwest Generation) is $79 million, $76 million of which is 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 the recorded liability by up to $125 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 the identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 32 immaterial sites whose total liability ranges from $3 million (the recorded minimum liability) to $8 million.

Edison International expects to clean up the 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 twelve months ended March 31, 2007 were $16 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 the 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.

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 March 31, 2007. Repayment of these deferred taxes would be accelerated if the IRS prevails:

As of March 31, 2007, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $419 million. The IRS also seeks a 20% penalty on any sustained tax adjustment.

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 no changes in Edison International’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, Edison International’s internal control over financial reporting.

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 April 30, 2007
Common Stock, no par value		325,811,206


		Page No.
Part I. Financial Information

Item 1.	Financial Statements:

	Consolidated Statements of Income – Three Months Ended March 31, 2007 and 2006	1

	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2007 and 2006	2

	Consolidated Balance Sheets – March 31, 2007 and December 31, 2006	3

	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2007 and 2006	5

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	74

Item 4.	Controls and Procedures	74

Part II. Other Information		75

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	75

Item 6.	Exhibits	76

Signature		77


Ninth Circuit		United States Court of Appeals for the Ninth Circuit

NO_X		nitrogen oxide

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

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

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)


	Three Months Ended March 31,
In millions, except per-share amounts	2007			2006
	(Unaudited)
Electric utility	$	2,222		$	2,217
Nonutility power generation		672			510
Financial services and other		18			24
Total operating revenue		2,912			2,751
Fuel		486			461
Purchased power		317			1,013
Provisions for regulatory adjustment clauses – net		289			(363	)
Other operation and maintenance		880			886
Depreciation, decommissioning and amortization		313			292
Total operating expenses		2,285			2,289
Operating income		627			462
Interest income		39			36
Equity in income from partnerships and unconsolidated subsidiaries – net		17			4
Other nonoperating income		17			42
Interest expense – net of amounts capitalized		(198	)		(200	)
Other nonoperating deductions		(11	)		(12	)
Income from continuing operations before tax and minority interest		491			332
Income tax expense		129			111
Dividends on preferred and preference stock of utility not subject to mandatory redemption		13			12
Minority interest		19			25
Income from continuing operations		330			184
Income from discontinued operations – net of tax		3			73
Income before accounting change		333			257
Cumulative effect of accounting change – net of tax		—			1
Net income	$	333		$	258
Weighted-average shares of common stock outstanding		326			326
Basic earnings per common share:
Continuing operations	$	1.00		$	0.56
Discontinued operations		0.01			0.22
Total	$	1.01		$	0.78
Weighted-average shares, including effect of dilutive securities		330			331
Diluted earnings per common share:
Continuing operations	$	1.00		$	0.56
Discontinued operations		0.01			0.22
Total	$	1.01		$	0.78
Dividends declared per common share	$	0.29		$	0.27


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



Btu		British Thermal units

Commonwealth Edison		Commonwealth Edison Company

CDWR		California Department of Water Resources

CPSD		Consumer Protection and Safety Division

CPUC		California Public Utilities Commission

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

DOE		United States Department of Energy

DWP		Los Angeles Department of Water & Power

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

GRC		General Rate Case

IRS		Internal Revenue Service

ISO		California Independent System Operator

kWh(s)		kilowatt-hour(s)

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

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

MW		megawatts

MWh		megawatt-hours

NAPP		Northern Appalachian


	Three Months Ended March 31,
In millions	2007			2006
	(Unaudited)
Net income	$	333		$	258
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments:
Other foreign currency translation adjustments – net		(2	)		—
Pension and postretirement benefits other than pensions:
Amortization of actuarial loss – net		1			—
Unrealized gain (loss) on cash flow hedges:
Other unrealized gain (loss) on cash flow hedges – net		(169	)		187
Reclassification adjustment for gain (loss) included in net income		16			(30	)
Other comprehensive income (loss)		(154	)		157
Comprehensive income	$	179		$	415


In millions	March 31, 2007			December 31, 2006
	(Unaudited)
ASSETS
Cash and equivalents	$	1,701		$	1,795
Restricted cash		57			59
Margin and collateral deposits		207			124
Receivables, less allowances of $26 and $29 for uncollectible accounts at respective dates		944			1,014
Accrued unbilled revenue		296			303
Fuel inventory		123			122
Materials and supplies		272			270
Accumulated deferred income taxes – net		299			203
Derivative assets		205			328
Regulatory assets		443			554
Short-term investments		475			558
Other current assets		255			152
Total current assets		5,277			5,482
Nonutility property – less accumulated provision for depreciation of $1,678 and $1,627 at respective dates		4,446			4,356
Nuclear decommissioning trusts		3,220			3,184
Investments in partnerships and unconsolidated subsidiaries		299			308
Investments in leveraged leases		2,510			2,495
Other investments		106			91
Total investments and other assets		10,581			10,434
Utility plant, at original cost:
Transmission and distribution		17,905			17,606
Generation		1,480			1,465
Accumulated provision for depreciation		(4,937	)		(4,821	)
Construction work in progress		1,578			1,486
Nuclear fuel, at amortized cost		176			177
Total utility plant		16,202			15,913
Regulatory assets		2,874			2,818
Restricted cash		55			91
Margin and collateral deposits		47			4
Derivative assets		100			131
Rent payments in excess of levelized rent expense under plant operating leases		604			556
Other long-term assets		899			832
Total long-term assets		4,579			4,432

Total assets	$	36,639		$	36,261


In millions, except share amounts	March 31, 2007			December 31, 2006
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Short-term debt	$	120		$	—
Long-term debt due within one year		372			488
Accounts payable		662			926
Accrued taxes		179			155
Accrued interest		222			196
Counterparty collateral		50			36
Customer deposits		207			198
Book overdrafts		164			140
Derivative liabilities		121			181
Regulatory liabilities		1,163			1,000
Other current liabilities		936			983
Total current liabilities		4,196			4,303
Long-term debt		9,091			9,101
Accumulated deferred income taxes – net		5,269			5,297
Accumulated deferred investment tax credits		121			122
Customer advances		162			160
Derivative liabilities		61			86
Power-purchase contracts		29			32
Accumulated provision for pensions and benefits		1,123			1,099
Asset retirement obligations		2,786			2,759
Regulatory liabilities		3,157			3,140
Other deferred credits and other long-term liabilities		1,468			1,267
Total deferred credits and other liabilities		14,176			13,962
Total liabilities		27,463			27,366
Commitments and contingencies (Note 6)
Minority interest		261			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)		2,082			2,080
Accumulated other comprehensive income (loss)		(76	)		78
Retained earnings		5,994			5,551
Total common shareholders’ equity		8,000			7,709

Total liabilities and shareholders’ equity	$	36,639		$	36,261


	Three Months Ended March 31,
In millions	2007			2006
	(Unaudited)
Cash flows from operating activities:
Net income	$	333		$	258
Less: income from discontinued operations – net of tax		3			73
Income from continuing operations		330			185
Adjustments to reconcile to net cash provided by operating activities:
Cumulative effect of accounting change – net of tax		—			(1	)
Depreciation, decommissioning and amortization		313			292
Realized loss on nuclear decommissioning trusts		8			—
Other amortization		31			21
Minority interest		19			25
Deferred income taxes and investment tax credits		(158	)		115
Equity in income from partnerships and unconsolidated subsidiaries		(16	)		(4	)
Income from leveraged leases		(16	)		(17	)
Regulatory assets – long-term		62			38
Regulatory liabilities – long-term		(11	)		(8	)
Levelized rent expense		(49	)		(49	)
Derivative assets – long-term		7			1
Derivative liabilities – long-term		(47	)		56
Other assets		(14	)		5
Other liabilities		229			(2	)
Margin and collateral deposits – net of collateral received		(112	)		28
Receivables and accrued unbilled revenue		77			347
Derivative assets – short-term		(17	)		188
Derivative liabilities – short-term		(129	)		52
Inventory and other current assets		(88	)		(43	)
Regulatory assets – short-term		111			(293	)
Regulatory liabilities – short-term		163			(177	)
Accrued interest and taxes		266			36
Accounts payable and other current liabilities		(253	)		(258	)
Distributions and dividends from unconsolidated entities		(1	)		2
Operating cash flows from discontinued operations		3			69
Net cash provided by operating activities		708			608
Cash flows from financing activities:
Long-term debt issued		30			500
Long-term debt issuance costs		(1	)		(5	)
Long-term debt repaid		(95	)		(578	)
Issuance of preference stock		—			196
Rate reduction notes repaid		(62	)		(62	)
Short-term debt financing – net		120			188
Change in book overdrafts		24			(76	)
Shares purchased for stock-based compensation		(103	)		(77	)
Proceeds from stock option exercises		39			21
Excess tax benefits related to stock option exercises		17			9
Dividends to minority shareholders		(24	)		(41	)
Dividends paid		(94	)		(88	)
Net cash used by financing activities	$	(149	)	$	(13	)


In millions	March 31, 2007		December 31, 2006
	(Unaudited)
Commercial paper	$	406	$	417
Certificates of deposit		69		141
Total	$	475	$	558


In millions	Three-Month Period Ended March 31,	2007			2006
Purchased-power expense		$	480		$	688
Unrealized (gains) / losses on economic hedging activities			(134	)		334
Energy settlements and refunds			(29	)		(9	)
Total purchased-power expense		$	317		$	1,013


			Weighted-Average
	Stock Options		Exercise Price		Remaining Contractual Term (Years)	Aggregate Intrinsic Value
Outstanding at December 31, 2006	14,111,697		$	26.33
Granted	1,729,422		$	47.42
Expired	—			—
Forfeited	(16,426	)	$	35.75
Exercised	(1,804,744	)	$	21.93
Outstanding at March 31, 2007	14,019,949		$	29.48	6.79
Vested and expected to vest at March 31, 2007	13,505,580		$	29.13	6.72	$	236,583,998
Exercisable at March 31, 2007	8,250,496		$	23.50	5.64	$	190,978,356


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		35
Southern California Edison Company		37
Edison Mission Group Inc.		42
Edison International (Parent)		60
Results of Operations and Historical Cash Flow Analysis		62
New Accounting Pronouncements		69
Commitments, Guarantees and Indemnities		70
Other Developments		71


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


	March 31, 2007				December 31, 2006
In millions	Assets		Liabilities		Assets		Liabilities
Energy options	$	—	$	27	$	—	$	10
FTRs		102		—		—		—
Forward physicals (power) and tolling arrangements		10		—		—		1
Gas options, swaps and forward arrangements		27		—		—		101
Total	$	139	$	27	$	—	$	112


In millions	April through December 2007		2008		2009
Illinois Plants
Plant capital expenditures	$	35	$	40	$	50
Environmental expenditures		21		39		66

Homer City Facilities
Plant capital expenditures		14		26		20
Environmental expenditures		6		9		15

Wind and Thermal Projects
Projects under construction		98		—		—
Turbine commitments		561		179		—
Other expenditures		54		—		—

Corporate capital expenditures		12		7		7
Total	$	801	$	300	$	158


Subsidiary	Financial Ratio	Covenant	Actual
Midwest Generation (Illinois plants)	Interest Coverage Ratio	Greater than or equal to 1.40 to 1	5.98 to 1
Midwest Generation (Illinois plants)	Secured Leverage Ratio	Less than or equal to 7.25 to 1	1.88 to 1
EME Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	3.20 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
Quarterly Average	$	44.81	$	42.48


	24-Hour Northern Illinois Hub Forward Energy Prices⁽¹⁾
2007
April	$	41.80
May		42.14
June		43.97
July		57.28
August		59.10
September		42.10
October		41.98
November		43.47
December		49.32
2008 Calendar “strip”⁽²⁾	$	47.92


	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
Quarterly Average	$	53.19	$	50.49	$	59.86	$	56.42


		24-Hour PJM West Hub Forward Energy Prices⁽¹⁾
2007
April		$ 52.35
May		53.03
June		57.33
July		76.64
August		79.32
September		55.00
October		54.72
November		56.49
December		61.30
2008 Calendar “strip”⁽²⁾		$ 63.37


	Amount of Coal Under Contract in Millions of Tons⁽¹⁾
	April through December 2007	2008	2009	2010
Illinois plants	12.5	14.6	11.7	11.7
Homer City facilities	3.9	2.1	0.8	—


In millions	Total Fair Value		Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	(94)	$	(71)	$	(23)	$	—	$	—


In millions
Fair value of trading contracts at January 1, 2007	$	111
Net gains from energy trading activities		28
Amount realized from energy trading activities		(32	)
Other changes in fair value		(11	)
Fair value of trading contracts at March 31, 2007	$	96


In millions		March 31, 2007
S&P Credit Rating:
A or higher		$ 12
A-		28
BBB+		55
BBB		38
BBB-		1
Below investment grade		—
Total		$ 134


In millions, except per-share amounts	Earnings (Loss)						Earnings (Loss) per Share
Three-Month Period Ended March 31,		2007			2006			2007			2006
Earnings (Loss) from Continuing Operations:
SCE	$	180		$	121		$	0.55		$	0.37
EMG		155			73			0.48			0.23
Edison International (parent) and other		(5	)		(10	)		(0.03	)		(0.04	)
Edison International Consolidated Earnings from Continuing Operations		330			184			1.00			0.56
Earnings from Discontinued Operations		3			73			0.01			0.22
Cumulative Effect of Accounting Change		—			1			—			—
Edison International Consolidated	$	333		$	258		$	1.01		$	0.78


In millions	2007 vs. 2006
Electric utility revenue
Rate changes (including unbilled)	$	127
Sales volume changes (including unbilled)		66
Balancing account over/under collections		(128	)
Sales for resale		(31	)
SCE’s VIEs		(23	)
Other (including inter company transactions)		(6	)
Total	$	5


In millions	Three-Month Period Ended March 31,
	2007	2006
SCE	$ 310	$ 311
EMG	176	150
Edison International Consolidated	$ 486	$ 461


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


Period	(a) Total Number of Shares (or Units) Purchased¹	(b) Average Price Paid per Share (or Unit)¹		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 1, 2007 to January 31, 2007	933,023	$	44.88	—	—

February 1, 2007 to February 28, 2007	595,622	$	46.56	—	—

March 1, 2007 to March 31, 2007	1,403,965	$	49.33	—	—
Total	2,932,610	$	47.35	—	—


10.1		Edison International 2007 Long-Term Incentives Terms and Conditions

10.2		Edison International Director Non-Qualified Stock Option Terms and Conditions

10.3		Edison International 2007 Performance Incentive Plan (File No. 1-9936, filed as Exhibit A to the Edison International and Southern California Edison Joint Proxy Statement filed on March 16, 2007)*

10.4		Edison International 2007 Executive Bonus Program (File No. 1-9936, filed as Exhibit 10.2 to Edison International Form 8-K dated April 26, 2007 and filed on May 2, 2007)*

10.5		Amended and Restated Credit Agreement, dated as of February 23, 2007, among Edison International and JPMorgan Chase Bank, N.A., as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, and Credit Suisse, Lehman Commercial Paper Inc., and Wells Fargo Bank, N.A., as Documentation Agents and the lenders thereto

31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act

31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act

32		Statement Pursuant to 18 U.S.C. Section 1350