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, 2008 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, 2007 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 2007 Annual Report on Form 10-K. Edison International follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2008 as discussed below in “Margin and Collateral Deposits” and “New Accounting Pronouncements.”

Certain prior-year reclassifications have been made to conform to the current year financial statement presentation mostly pertaining to the adoption of FIN No. 39-1. Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.

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

Stock-based compensation awards to purchase 83,901 and 1,731,108 shares of common stock for the three months ended March 31, 2008 and 2007, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares; and therefore, the effect would have been antidilutive.

Margin and collateral deposits include margin requirements and cash deposited with and received from counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits varies based on changes in the value of the agreements. See “New Accounting Pronouncements” below for a discussion of the adoption of FIN No. 39-1. In accordance with FIN No. 39-1, Edison International presents a portion of its margin and cash collateral deposits net with its derivative positions on its consolidated balance sheets. Amounts recognized for cash collateral provided to others that have been offset against net derivative liabilities totaled $134 million and $ 38 million at March 31, 2008 and December 31, 2007, respectively. Amounts recognized for cash collateral received from others that have been offset against net derivative assets totaled $10 million at March 31, 2008.

In April 2007, the FASB issued FIN No. 39-1. This pronouncement permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. In addition, upon the adoption, companies were permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting agreements. Edison International adopted FIN No. 39-1 effective January 1, 2008. The adoption resulted in netting a portion of margin and cash collateral deposits with derivative positions on Edison International’s consolidated balance sheets, but had no impact on its consolidated statements of income. The consolidated balance sheet at December 31, 2007 has been retroactively restated for the change, which resulted in a decrease in net assets (margin and collateral deposits) of $38 million. The consolidated statements of cash flows for the three months ended March 31, 2007 has been retroactively restated to reflect the balance sheet changes, which had no impact on total operating cash flows from continuing operations.

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. Edison International adopted this pronouncement effective January 1, 2008. The adoption had no impact because Edison International did not make an optional election to report additional financial assets and liabilities at fair value.

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. Edison International adopted SFAS No. 157 effective January 1, 2008. The adoption did not result in any retrospective adjustments to its consolidated financial statements. The accounting requirements for employers’ pension and other postretirement benefit plans are effective at the end of 2008, which is the next measurement date for these benefit plans. The effective date will be January 1, 2009 for asset retirement obligations and other nonfinancial assets and liabilities which are measured or disclosed on a non-recurring basis. For further discussion, see Note 8.

In December 2007, the FASB issued SFAS No. 141(R), which establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS No. 141(R) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning on or after January 1, 2009. Early adoption is not permitted.

In December 2007, the FASB issued SFAS No. 160, which requires an entity to present minority interest that reflects the ownership interests in subsidiaries held by parties other than the entity, within the equity section but separate from the entity’s equity in the consolidated financial statements. It also requires the amount of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated statement of income; changes in ownership interest be accounted for similarly as equity transactions; and, when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary be measured at fair value. Edison International will adopt SFAS No. 160 on January 1, 2009. In accordance with this standard, Edison International will reclassify minority interest to a component of shareholder’s equity (at March 31, 2008 this amount was $282 million).

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

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

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

During the first quarter of 2008, a subsidiary of EME was awarded, through a competitive bidding process, a ten-year power sales contract with SCE for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. The power sales agreement is subject to approval of the CPUC which SCE requested on April 4, 2008. CPUC approval is expected to be granted by late 2008. As an affiliate transaction, the contract is also subject to FERC approval, which was requested on May 2, 2008. Deliveries under the power sales agreement are expected to commence in 2013.

At March 31, 2008 and December 31, 2007, Edison International classified all marketable debt securities as held-to-maturity. The securities were carried at amortized cost plus accrued interest which approximated their fair value. Gross unrealized holding gains and losses were not material.

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

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

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

SCE’s short-term debt is generally used to finance fuel inventories, balancing account undercollections and general, temporary cash requirements including power-purchase payments. At March 31, 2008, the outstanding short-term debt was $400 million at a weighted-average interest rate of 3.36%. SCE’s short-term debt is supported by a $2.5 billion credit line. See below in “Credit Agreement Amendments.”

On March 12, 2008, both Edison International and SCE amended their existing credit facilities, extending the maturities to February 2013 while retaining existing borrowing costs as specified in the facilities. The amendments also provide four extension options which, if all exercised, will result in final terminations of February 2017. At March 31, 2008, SCE’s $2.5 billion credit facility supported $217 million in letters of credit and $400 million of short-term debt outstanding, leaving $1.88 billion available for liquidity purposes. At March 31, 2008, all of Edison International’s (parent) $1.5 billion credit facility was available for liquidity purposes.

Edison International’s composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. Edison International’s effective tax rate from continuing operations was 35% for the three months ended March 31, 2008, as compared to 28% for the respective period in 2007. The increased effective tax rate was caused primarily by reductions made to the income tax reserve during the first quarter of 2007 to reflect progress in an administrative appeals process with the IRS related to SCE’s income tax treatment of costs associated with environmental remediation.

Pursuant to the requirements of FIN 48, Edison International records tax reserves for uncertain tax return positions taken or expected to be taken on tax returns. Edison International also has filed affirmative tax claims related to uncertain tax positions, which, if accepted, could result in refunds of taxes paid or additional tax benefits for positions not reflected on filed original tax returns. FIN 48 requires the disclosure of all unrecognized tax benefits, which includes the reserves recorded for uncertain tax positions on filed tax returns and the unrecognized portion of affirmative claims.

The following table provides a reconciliation of unrecognized tax benefits from January 1, 2008 to March 31, 2008:

The unrecognized tax benefits in the table above reflects affirmative claims related to timing differences of $1.5 billion and $1.6 billion at March 31, 2008 and January 1, 2008, respectively, but have not met the recognition threshold pursuant to FIN 48 and have been denied by the IRS as part of their examinations. These affirmative claims remain unpaid by the IRS and no receivable has been recorded. Edison International is vigorously defending these affirmative claims in IRS administrative appeals proceedings.

It is reasonably possible that Edison International could reach a settlement with the IRS to all or a portion of the unrecognized tax benefits through tax year 2002 within the next 12 months, which could reduce unrecognized tax benefits by up to $1.2 billion.

The total amount of unrecognized tax benefits as of March 31, 2008 and January 1, 2008 that, if recognized, would have an effective tax rate impact is $203 million and $206 million, respectively.

The total amount of accrued interest and penalties were $176 million and $162 million as of March 31, 2008 and January 1, 2008, respectively. For the three months ended March 31, 2008, $8 million of after-tax interest expense was recognized and included in income tax expense.

Tax Positions being addressed as part of active examinations and administrative appeals processes

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

During the examination phase for tax years 1994 – 1999, which is complete, the IRS asserted income tax deficiencies related to certain tax positions taken by Edison International on filed tax returns. Edison International is challenging the asserted tax deficiencies in IRS administrative appeals proceedings; however, most of these tax positions relate to timing differences and, therefore, any amounts that would be paid if Edison International’s position is not sustained (exclusive of any penalties) would be deductible on future tax returns filed by Edison International. In addition, Edison International has filed affirmative claims with respect to certain tax years 1986 through 2005 with the IRS and state tax authorities. Any benefits associated with these affirmative claims would be recorded in accordance with FIN 48 which provides that recognition would occur at the earlier of when Edison International would make an assessment that the affirmative claim position has a more likely than not probability of being sustained or when a settlement of the affirmative claim is consummated with the tax authority. Certain of these affirmative claims have been recognized as part of the implementation of FIN 48.

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

As part of a nationwide challenge of certain types of lease transactions, the IRS has asserted deficiencies related to Edison International’s deferral of income taxes associated with certain of its cross-border, leveraged leases. For tax years 1994 – 1999, Edison International is challenging the asserted deficiencies in ongoing IRS Appeals proceedings.

These asserted deficiencies relate to Edison Capital’s income tax treatment of both its 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) and its 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).

In 1999, Edison Capital entered into a lease/service contract transaction involving a foreign telecommunication system (Service Contract, which the IRS also refers to as a SILO). As part of an ongoing examination of 2000 – 2002, the IRS is reviewing Edison International’s income tax treatment of this Service Contract and has issued several data requests, to which Edison International has responded. The IRS has not formally asserted any adjustments, but Edison International believes that the IRS examination team will assert deficiencies related to this Service Contract. The following table summarizes estimated federal and state income taxes deferred from these leases as of December 31, 2007. Repayment of these deferred taxes would be accelerated if the IRS position were to be sustained:

As of March 31, 2008, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $557 million. The IRS has also asserted 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 with the Administrative Appeals branch of the IRS through pending appeals of the deficiencies and penalties asserted by IRS examination for the tax years 1994 – 1999. Edison International believes the IRS’s position misstates material facts, misapplies the law and is incorrect. Currently, Edison International is engaged in settlement discussions with IRS Appeals.

for as a deposit recorded in “Other long-term assets” on the consolidated balance sheet and 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 which provides Edison International with the option of being able to take legal action to assert its refund claim.

A number of cases involving LILO and SILO transactions are pending before various federal courts. One case involving a LILO transaction was decided in favor of the IRS in a federal district court and was affirmed in a Circuit Court of Appeals decision issued in April 2008. In April 2008, a jury in a federal district court case rendered a verdict where some of the findings were unfavorable to the taxpayer. The taxpayer has asserted in a post-verdict motion that these findings are inconsistent. This case is awaiting a final judgment. In accordance with FIN 48 and FASB Staff Position FAS 13-2 “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction,” Edison International will continue to monitor and evaluate its lease transactions with respect to on-going events. Edison International cannot predict the timing or ultimate outcome of these cases or any of the other pending LILO or SILO cases or other developments.

To the extent an acceptable settlement is not reached with the IRS, Edison International would expect to file a refund claim for any taxes and penalties that are paid for the 1994 –1996 tax years related to assessed tax deficiencies and penalties on the Replacement Leases. Edison International may make additional payments related to later tax years to preserve its litigation rights. Although, at this time, the amount and timing of these additional payments is uncertain, the amount of additional payments, if necessary, could be substantial. At this time, Edison International is unable to predict the impact of the ultimate resolution of the lease issues.

Edison International filed amended California Franchise Tax 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 described above and the SCE subsidiary contingent liability company transaction described below. Edison International filed these amended returns under protest retaining its appeal rights.

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

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

Resolution of Federal and State Income Tax Issues Being Addressed in Ongoing Examinations and Administrative Appeals

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

As of March 31, 2008, Edison International had made $7 million in contributions related to 2007 and $14 million related to 2008 and estimates to make $46 million of additional contributions in the last nine months of 2008. Expected contribution funding in 2008 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.

As of March 31, 2008, Edison International had made no contributions related to 2007 and $5 million related to 2008 and estimates to make $49 million of additional contributions in the last nine months of 2008. Expected contribution funding in 2008 could vary from anticipated amounts, depending on the funded status at year-end and tax-deductible funding limitations.

During the first quarter of 2008, Edison International granted its 2008 stock-based compensation awards, which included stock options, performance shares, deferred stock units and restricted stock units. Total stock-based compensation expense (reflected in the caption “Other operation and maintenance” on the consolidated

statements of income) was $7 million for both of the three months ended March 31, 2008 and 2007. The income tax benefit recognized in the consolidated statements of income was $3 million for both of the three months ended March 31, 2008 and 2007. Total stock-based compensation cost capitalized was $1 million for both three months ended March 31, 2008 and 2007.

The amount of cash used to settle stock options exercised was $13 million and $86 million for the three months ended March 31, 2008 and 2007, respectively. Cash received from options exercised was $7 million and $39 million for the three months ended March 31, 2008 and 2007, respectively. The estimated tax benefit from options exercised was $3 million and $18 million for the three months ended March 31, 2008 and 2007, 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 2007 Annual Report on Form 10-K for a detailed discussion.

SCE entered into service contracts associated with uranium enrichment and fuel fabrication during the first three months of 2008. As a result, SCE’s additional fuel supply commitments are estimated to be $23 million for the remainder of 2008, $31 million for 2009, $31 million for 2010, $51 million for 2011, $91 million for 2012 and $204 million thereafter.

At March 31, 2008, EME’s subsidiaries had firm commitments to spend approximately $240 million during the remainder of 2008 and $4 million in 2009 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects. These expenditures are planned to be financed by cash on hand, cash generated from operations or existing subsidiary credit agreements.

At March 31, 2008, EME had entered into agreements with vendors securing 483 wind turbines (1,076 MW) for an aggregate purchase price of $1.3 billion, with remaining commitments of $474 million in 2008, $540 million in 2009 and $49 million in 2010. At March 31, 2008, EME had recorded wind turbine deposits of $197 million

included in other long-term assets in its consolidated balance sheet. In addition, EME had 30 wind turbines (90 MW) in temporary storage to be used for future wind projects with remaining commitments of $3 million in 2008. At March 31, 2008, EME had recorded $84 million related to these wind turbines included in other long-term assets in its consolidated balance sheet.

In connection with the acquisition of the Illinois Plants, Midwest Generation had assumed a long-term coal supply contract and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buy out its coal obligations for the years 2009 through 2012 under this contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million, after tax) during the first quarter of 2008. The remaining payments due under this contract are $20 million.

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

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

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the

automatic renewal provision, it has been extended until February 2009. 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 211 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at March 31, 2008. Midwest Generation had recorded a $54 million liability at March 31, 2008 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, 2008, EME had recorded a liability of $108 million related to these matters.

In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At March 31, 2008, EME had recorded a liability of $13 million related to these matters.

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. The obligations under this indemnification agreement as of March 31, 2008, if payment were required, would be $67 million. EME has not recorded a liability related to this indemnity.

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific environmental claims related to SCE’s previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilities with respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to

the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.

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

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 consolidated results of operations or liquidity.

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 consolidated 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, 2008, Edison International’s recorded estimated minimum liability to remediate its 44 identified sites at SCE (24 sites) and EME (20 sites primarily related to Midwest Generation) was $68 million, $64 million of which was related to SCE including $29 million related to San Onofre. This remediation liability is undiscounted. 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 $150 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 30 immaterial sites whose total liability ranges from $3 million (the recorded minimum liability) to $9 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $33 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 $62 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

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

Edison International expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $11 million to $31 million. Recorded costs for the 12 months ended March 31, 2008 were $23 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 consolidated results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

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 certain lease and kind of lease transactions. See Note 3, for further details.

In October 2006, EMMT was advised by the enforcement staff at the FERC that it is prepared to recommend that the FERC initiate a formal investigatory proceeding and seek monetary sanctions against EMMT for alleged

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

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

The order also grants a higher return on equity on SCE’s entire transmission rate base in SCE’s next FERC transmission rate case for SCE’s participation in the CAISO. SCE has not yet determined when it expects to file its next FERC rate case. In addition, the order permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction, also known as CWIP, of all three projects and 100% recovery of prudently-incurred abandoned plant costs for DPV2 and Tehachapi, if either or both of these projects are cancelled due to factors beyond SCE’s control.

On December 21, 2007, SCE filed a revision to its Transmission Owner Tariff to collect 100% of CWIP in rate base for Tehachapi, DPV2, and Rancho Vista, as authorized by FERC in its transmission incentives order discussed above. In the CWIP filing, SCE proposed a single-issue rate adjustment ($45 million or a 14.4% increase) to SCE’s currently authorized base transmission revenue requirement to be made effective on March 1, 2008 and later adjusted for amounts actually spent in 2008 through a new balancing account mechanism. The rate adjustment represents actual expenditures from September 1, 2005 through November 30, 2007, projected expenditures from December 1, 2007 through December 31, 2008, and a ROE (which includes the ROE adders approved for Tehachapi, DPV2 and Rancho Vista). SCE projects that it will spend a total of approximately $244 million, $27 million, and $181 million for Tehachapi, DPV2, and Rancho Vista, respectively, from September 1, 2005 through the end of 2008. The 2008 DPV2 expenditure forecast is limited to projected consulting and legal costs associated with SCE’s continued efforts to obtain regulatory approvals necessary to construct the DPV2 Project. On February 29, 2008, the CWIP filing was approved and SCE implemented the CWIP rate on March 1, 2008, subject to refund on the limited issue of whether SCE’s proposed ROEs are reasonable. In the order, SCE was also directed by FERC to make a compliance filing to provide greater detail on the costs reflected in CWIP rates for 2008. SCE made the compliance filing on March 31, 2008. On April 21, 2008, the CPUC filed a protest of the compliance filing at FERC and requested an evidentiary hearing to be set to further review the costs. SCE intends to file a response to the CPUC’s protest, which rejects the CPUC’s request for a further hearing. In addition, on March 1, 2008, the CPUC filed a Petition for Rehearing with the FERC on the FERC’s acceptance of SCE’s proposed ROE for CWIP. SCE cannot predict the outcome of this proceeding.

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 has already received. SCE has also proposed to withdraw the pending rewards for the 2001 – 2003 time frames.

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

In light of the problems uncovered with the PBR mechanisms discussed above, SCE conducted an investigation into the third PBR metric, system reliability for the years 1997 – 2003. SCE received $8 million in reliability incentive awards for the period 1997 – 2000 and applied for a reward of $5 million for 2001. For 2002, SCE’s data indicated that it earned no reward and incurred no penalty. For 2003, based on the application of the PBR mechanism, it would incur a penalty of $3 million and accrued a charge for that amount in 2004. On February 28, 2005, SCE provided its final investigation report to the CPUC concluding that the reliability reporting system was working as intended.

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

On October 1, 2007, a POD was released ordering SCE to refund $136 million, before interest, and pay a statutory penalty of $40 million. Included in the amount to be refunded are $28 million related to customer satisfaction rewards, $20 million related to employee safety rewards, and $77 million related to results sharing. The decision requires that the proposed results sharing refund of $77 million (based on year 2000 data) be adjusted for attrition and escalation which increases the results sharing refund to $88 million. Interest as of December 31, 2007, based on amounts collected for customer satisfaction, employee safety incentives and results sharing, including escalation and attrition adjustments, would add an additional $28 million to this amount. The POD also requires SCE to forgo $35 million in rewards for which it would have otherwise been eligible. Included in the amount to be forgone is $20 million related to customer satisfaction rewards and $15 million related to employee safety rewards.

On October 31, 2007, SCE appealed the POD to the CPUC. The CPSD and an intervenor also filed appeals. The CPSD appeal requested that: (1) the statutory penalty be increased from $40 million to $83 million, (2) a penalty be imposed under the PBR customer satisfaction and employee safety mechanisms in the amount of $48 million and $35 million, respectively, and (3) SCE refund/forgo rewards earned under the customer satisfaction and employee safety mechanisms of $48 million and $35 million, respectively. The appealing intervenor asked that the statutory penalty be increased to as much as $102 million. Oral argument on the appeals took place on January 30, 2008, and it is uncertain when the CPUC will issue a decision.

SCE cannot predict the outcome of the appeal. Based on SCE’s proposed refunds, the combined recommendations of the CPSD and other intervenors, as well as the POD, the potential refunds and penalties could range from $52 million up to $388 million. SCE has recorded an accrual at the lower end of this range of potential loss and is accruing interest (approximately $16 million as of March 31, 2008) on collected amounts.

The system reliability component of PBR was not addressed in the POD. Pursuant to an earlier order in the case, system reliability incentives will be addressed in a second phase of the proceeding, which commenced with the

filing of SCE’s opening testimony in September 2007. In that testimony, SCE confirmed that its PBR system reliability results, which reflected rewards of $13 million for 1997 through 2002 and a penalty of $3 million in 2003 were valid. An indefinite suspension of the schedule for the second phase of the proceeding pending resolution of the appeals of the POD has been granted. SCE cannot predict the outcome of the second phase.

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. The order reversed an arbitrator’s award that had affirmed the ISO’s characterization in May 2000 of the charges as Intra-Zonal Congestion costs and allocation of those charges to scheduling coordinators in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from scheduling coordinators in the affected zone to the responsible participating transmission owner, SCE. The potential cost to SCE, net of amounts SCE expects to receive through the PX, SCE’s scheduling coordinator at the time, is estimated to be approximately $20 million to $25 million, including interest. On April 20, 2005, the FERC stayed its April 20, 2004 order during the pendency of SCE’s appeal filed with the Court of Appeals for the D.C. Circuit. On March 7, 2006, the Court of Appeals remanded the case back to the FERC at the FERC’s request and with SCE’s consent. On March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. On May 25, 2007, the FERC issued a procedural order granting the rehearing application for the limited purpose of allowing the FERC to give it further consideration. In a future order, FERC may deny the rehearing request or grant the requested relief in whole or in part. SCE believes that the most recent substantive FERC order correctly allocates responsibility for these ISO charges. However, SCE cannot predict the final outcome of the rehearing. If a subsequent regulatory decision changes the allocation of responsibility for these charges, and SCE is required to pay these charges as a transmission owner, SCE may seek recovery in its reliability service rates. SCE cannot predict whether recovery of these charges in its reliability service rates would be permitted.

At March 31, 2008, Edison Capital had a net leveraged lease investment, before deferred taxes, of $53 million in three aircraft leased to American Airlines. American Airlines has reported net loss for its first quarter 2008 and previously reported 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, 2008, American Airlines was current in its lease payments to Edison Capital.

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

The claims asserted against Midway-Sunset for refunds related to power sold into the PX market, 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 market on behalf of SCE and PG&E in excess of the amounts to which it was entitled under the pre-existing power sales contracts, but instead passed through those proceeds to the utilities. 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 market on their behalves.

On December 20, 2007, Midway-Sunset entered into a settlement agreement with SCE, PG&E, SDG&E and certain California state parties to resolve Midway-Sunset’s liability in the FERC refund proceedings. Midway-Sunset concurrently entered into a separate agreement with SCE and PG&E that provides for pro-rata reimbursement to Midway-Sunset by the two utilities of the portions of the agreed to refunds that are attributable to sales made by Midway-Sunset for the benefit of the utilities. The settlement, which had been approved previously by the CPUC was approved by FERC on April 2, 2008.

During the period in which Midway-Sunset’s generation was sold into the PX market, amounts SCE received from Midway-Sunset for its pro-rata share of such sales were credited to SCE’s customers against power purchase expenses through the ratemaking mechanism in place at that time. SCE believes that the net amounts to be reimbursed to Midway-Sunset are recoverable from its customers through current regulatory mechanisms. Edison International does not expect any refund payment to be made by Midway-Sunset, or any SCE reimbursement to Midway-Sunset, to have a material impact on earnings.

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990’s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the Clean Air Act, including alleged requirements to obtain a construction permit and to install best available control technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the Clean Air Act. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. Midwest Generation, Commonwealth Edison, the US EPA, and the United States Department of Justice (DOJ) are in talks designed to explore the possibility of a settlement. If the settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. As a result, Midwest Generation is investigating the claims made by the US EPA in the NOV and has identified several defenses which it will raise if the government files suit. At this early stage in the process, Midwest Generation cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.

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

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

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

punitive damages of not less than $1 billion. In March 2001, the Hopi Tribe was permitted to intervene as an additional plaintiff but has not yet identified a specific amount of damages claimed.

In April 2004, the D.C. District Court denied SCE’s motion for summary judgment and concluded that a 2003 U.S. Supreme Court decision in an on-going related lawsuit by the Navajo Nation against the U.S. Government did not preclude the Navajo Nation from pursuing its RICO and intentional tort claims. In September 2007, the Federal Circuit reversed a lower court decision on remand in the related lawsuit, finding that the U.S. Government had breached its trust obligation in connection with the setting of the royalty rate for the coal supplied to Mohave. Subsequently, the Federal Circuit denied the U.S. Government’s petition for rehearing. The U.S. Government may, however, still seek review by the Supreme Court of the Federal Circuit’s September decision. The Government’s deadline for seeking such review has been extended to May 13, 2008.

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

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $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 approximately $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 at least once every five years beginning August 20, 2003. The next inflation adjustment should occur no later than August 20, 2008. Based on its ownership interests, SCE could be required to pay a maximum of approximately $201 million per nuclear incident. However, it would have to pay no more than approximately $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 law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further revenue.

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

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

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

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

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

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

customers through SCE’s transmission rates and on December 11, 2007, the FERC accepted SCE’s proposed transmission rates reflecting the forecast levels of costs associated with the settlement. Upon signing of the agreement in January 2008, SCE recorded a regulatory asset and recognized in earnings the amount of scheduling coordinator charges to be collected through rates. SCE filed a refund report with the FERC on March 4, 2008. Subsequently, DWP filed with FERC two separate requests to extend the comment period for the refund report in order to verify that the amounts refunded by SCE to DWP are appropriate. The deadline for comments is now May 27, 2008. SCE expects that there will be no material change to the refunds provided to DWP as a result of DWP’s review of the refund report.

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its obligation to begin acceptance of spent nuclear fuel not later than January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to 0.1¢ per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE’s failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. The case was stayed through April 7, 2006, when SCE and the DOE filed a Joint Status Report in which SCE sought to lift the stay and the government opposed lifting the stay. On June 5, 2006, the Court of Federal Claims lifted the stay on SCE’s case and established a discovery schedule. In a Joint Status Report filed on February 22, 2008, the parties agreed that a trial date should be set. SCE requested that a trial date be set as soon as practicable and the government requested that the trial not occur before November 2008, due to government resource commitments regarding other pending cases. The Court has not yet acted on the requests for a trial date.

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

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

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

Unrealized losses on cash flow hedges, net of tax, at March 31, 2008, included unrealized losses on commodity hedges related to Midwest Generation and EME Homer City futures and forward electricity contracts that qualify for hedge accounting. These losses arise because current forecasts of future electricity prices in these markets are greater than the contract prices. As EME’s hedged positions for continuing operations are realized, $149 million, after tax, of the net unrealized losses on cash flow hedges at March 31, 2008 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized losses will decrease energy revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which a cash flow hedge is designated is through December 31, 2010.

Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net losses of $13 million and $1 million during the first quarters of 2008 and 2007, respectively, representing the amount of cash flow hedges’ ineffectiveness for continuing operations, reflected in nonutility power generation revenue in Edison International’s consolidated income statements.

In connection with certain wind projects acquired during March 2007, the purchase price included payments that were due upon the start and/or completion of construction. Accordingly, EME accrued for estimated payments during the first quarter of 2007 which were due upon commencement of construction in 2007 and/or completion of construction scheduled during 2008.

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an “exit price” in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability should reflect the entity’s nonperformance risk.

The standard establishes a hierarchy for fair value measurements. Financial assets and liabilities carried at fair value on a recurring basis are classified and disclosed in the three categories outlined below:

Edison International’s assets and liabilities carried at fair value primarily consist of derivative positions for both SCE and EME. These positions may include forward sales and purchases of physical power, options and forward price swaps which settle only on a financial basis (including futures contracts). In addition, SCE nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed income securities.

Level 1 includes derivatives that are exchange traded, as well as SCE’s nuclear decommissioning trust investments in equity and U.S. treasury securities. The fair values for these derivatives and equity securities are determined using quoted exchange transaction market prices. U.S. treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market.

Level 2 includes non-exchange traded derivatives using over-the-counter markets. The fair value of these derivatives is determined using forward market prices adjusted for credit risk. The majority of EME’s Level 2 derivatives are entered into for hedging purposes. Level 2 also includes SCE’s nuclear decommissioning trust investments in other fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

Level 3 includes the majority of SCE’s derivatives, including over-the-counter options, bilateral contracts, FTRs and CRRs in the California market, capacity and QF contracts. The fair value of these SCE derivatives is determined using uncorroborated broker quotes and models that mainly extrapolate short-term observable inputs. Level 3 also includes derivatives that trade infrequently such as FTRs and over-the-counter derivatives at illiquid locations and long-term power agreements. Where Edison International does not have observable market prices, Edison International believes that the transaction price is the best estimate of fair value at inception. For illiquid FTRs, Edison International reviews objective criteria related to system congestion on a quarterly basis and other underlying drivers and adjusts fair value when Edison International concludes a change in objective criteria would result in a new valuation that better reflects the fair value. Changes in fair values are based on hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit and liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods.

In circumstances where Edison International cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets

continue to develop and more pricing information becomes available, Edison International continues to assess valuation methodologies used to determine fair value.

When appropriate, valuations are adjusted for various factors including liquidity, bid/offer spreads and credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.

The following table sets forth financial assets and liabilities that were accounted for at fair value as of March 31, 2008 by level within the fair value hierarchy.

The following table sets forth a summary of changes in the fair value of Level 3 derivative contracts, net for the three months ended March 31, 2008.

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

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Net earnings were $31 million and $37 million for the three months ended March 31, 2008 and 2007, respectively. Proceeds from sales of securities (which are reinvested) were $829 million and $1.0 billion for the three months ended March 31, 2008 and 2007, respectively. Cumulative unrealized holding gains, net of losses, were $994 million and $1.1 billion at March 31, 2008 and December 31, 2007, respectively. Realized losses for other-than-temporary impairments were $45 million and $8 million for the three months ended March 31, 2008 and 2007, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible.

In January 2008, SCE repurchased 350,000 shares of 4.08% cumulative preferred stock at a price of $19.50 per share. SCE retired this preferred stock in January 2008 and recorded a $2 million gain on the cancellation of reacquired capital stock (reflected in the caption “Common stock” on the consolidated balance sheets). There is no sinking fund requirement for redemptions or repurchases of preferred stock.

Edison International’s reportable business segments include its electric utility operation segment (SCE), a nonutility power generation segment (EME), and a financial services provider segment (Edison Capital). Included in the nonutility power generation segment are the activities of MEHC, the holding company of EME. MEHC’s only substantive activities were its obligations under the senior secured notes which were paid in full on June 25, 2007. MEHC does not have any substantive operations. Edison International evaluates performance based on net income.

SCE is a rate-regulated electric utility that supplies electric energy to a 50,000 square-mile area of central, coastal and Southern California. SCE also produces electricity. EME is engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from electric power generation facilities. EME also conducts hedging and energy trading activities in power markets open to competition. Edison Capital is a provider of financial services with investments worldwide.

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

This MD&A for the three months ended March 31, 2008 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2007, and as compared to the three months ended March 31, 2007. This discussion presumes that the reader has read or has access to Edison International’s MD&A for the calendar year 2007 (the year-ended 2007 MD&A), which was included in Edison International’s 2007 annual report to shareholders and incorporated by reference into Edison International’s Annual Report on Form 10-K for the year ended December 31, 2007, 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 Annual Report on Form 10-K. Readers are urged to read this entire report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect Edison International’s business. Forward-looking statements speak only as of the date they are made and Edison International is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International with the Securities & Exchange Commission.

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

In this MD&A, except when stated to the contrary, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to Edison International (parent) or parent company mean Edison International 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, 2007. 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 November 19, 2007, SCE filed its GRC application requesting a 2009 base rate revenue requirement of $5.199 billion, an increase of approximately $858 million over the projected authorized base rate revenue requirements. After considering the effects of sales growth and other offsets, SCE’s request would be a $726 million increase over current authorized base rate revenue. On April 15, 2008, the DRA submitted testimony recommending that SCE’s 2009 base rate revenue requirement be increased by approximately $7 million, a difference of $719 million from SCE’s request. The $719 million difference is mainly due to reductions proposed by DRA including: recommended changes in methods for calculating depreciation expense; reductions in operations and maintenance expense; reductions in pensions and benefits; the elimination of amounts collected in rates for employee bonuses (“results sharing”) as well as the reduction in long-term incentives and other executive compensation; and other miscellaneous proposed reductions. Testimony submitted by TURN, another intervenor, seeks to reduce SCE’s 2009 request by an additional $195 million over the DRA proposed adjustments, mainly due to reduced depreciation expense. In addition, TURN intends to propose additional adjustments related to the treatment of Mohave, replaced meters, software costs and other operating revenue sharing mechanisms. See “SCE: Regulatory Matters —Current Regulatory Developments—2009 General Rate Case Proceeding” for further discussion.

On December 21, 2007, the CPUC granted SCE’s requested rate-making capital structure of 43% long-term debt, 9% preferred equity and 48% common equity for 2008. The CPUC also authorized SCE’s 2008 cost of long-term debt of 6.22%, cost of preferred equity of 6.01% and a return on common equity of 11.5%. The impact of this Phase I decision resulted in a $7 million decrease in SCE’s annual revenue requirement. On April 29, 2008, the CPUC issued a proposed decision on Phase II of the proceeding, replacing the current annual cost of capital application with a multi-year mechanism which would not require a new cost of capital application to be filed until April 2010. The proposed decision would also adopt a trigger mechanism which provides for an automatic ROE adjustment during the intervening years between the cost of capital filings if certain thresholds are reached. A final decision is expected to be issued in May 2008.

On March 27, 2008, SCE filed an application with the CPUC to implement its Solar Photovoltaic (PV) Program to develop up to 250 MW of utility-owned Solar PV generating facilities ranging in size from 1 to 2 MW each. Targeted at commercial and industrial rooftop space in SCE’s service territory, SCE’s program will use rooftop space from entities that would not otherwise be typical candidates for the net energy metering tariff, which allows customers to offset their usage with electricity generated at their own facilities. SCE proposes to develop these projects at a rate of approximately 50 MW per year at an average cost of $3.50/watt. The estimated base case capital cost for the Solar PV Program is $875 million over the 5 year period of the program. SCE proposes a reasonableness threshold of $963 million. Subject to CPUC approval, the capital expenditures will be eligible to be included in SCE’s earning asset base if the actual costs of the program are equal to or lower than the reasonableness threshold amount. SCE also proposes to apply the CPUC-approved 100 basis point incentive adder for qualifying utility-owned renewable energy investments.

At March 31, 2008, EME had 566 MW of wind projects in service and another 447 MW of wind projects under construction, with scheduled completion dates during 2008. As of the same date, EME had a development pipeline of potential wind projects with an estimated installed capacity of approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. This development pipeline is supported by turbine purchase commitments and turbines in storage totaling 1,166 MW for new wind projects. The majority of the turbines are scheduled to be delivered before the end of 2009.

During the first quarter of 2008, EME commenced pre-construction activities (approximately $55 million committed to date) for a 240 MW planned wind project in Illinois, referred to as the Big Sky project. The project plans to sell electricity into the PJM market as a merchant generator. Pre-construction activities will be limited to equipment purchases, site development and interconnection activities, pending resolution of wind turbine performance issues noted below. Commercial operations of the Forward wind project (29 MW) and Phase I of the Goat Mountain wind project (80 MW) commenced during April 2008.

During the first quarter of 2008, a subsidiary of EME was awarded through a competitive bidding process a ten-year power sales contract with SCE for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. The power sales agreement is subject to approval of the CPUC which SCE requested on April 4, 2008. CPUC approval is expected to be granted by late 2008. As an affiliate transaction, the contract is also subject to FERC approval, which was requested on May 2, 2008. Deliveries under the power sales agreement are expected to commence in 2013. Subsequent to March 31, 2008, EME and its subsidiary entered into an agreement to purchase major equipment for the project and, subsequently made equipment deposits of $21 million. The total project costs, excluding interest during construction, are estimated in the range of $500 million to $600 million.

Included as part of the wind projects or turbine purchase commitments described above, EME has purchased 475 turbines from Suzlon Wind Energy Corporation (Suzlon) and 71 turbines from Clipper Turbine Works, Inc. (Clipper). Rotor blade cracks were identified on certain Suzlon wind turbines, and rotor blade and gearbox problems were identified on certain Clipper wind turbines. Clipper has commenced its remediation plans that are designed to correct the current deficiencies, at its cost. EME is continuing to work with Suzlon to analyze the root causes of the performance issues and address commercial matters that result from the impact of these issues on EME and its projects. For further discussion, refer to “EMG: Liquidity—Capital Expenditures—Wind Turbine Performance Issues” in the year-ended 2007 MD&A.

As of March 31, 2008, SCE had cash and equivalents of $282 million ($113 million of which was held by SCE’s consolidated VIEs). As of March 31, 2008, long-term debt, including current maturities of long-term debt, was $5.47 billion. On March 12, 2008, SCE amended its existing $2.5 billion credit facility, extending the maturity to February 2013 while retaining existing borrowing costs as specified in the facility. The amendment also provides four extension options which, if all exercised, will result in a final termination of February 2017. At March 31, 2008, the credit facility supported $217 million in letters of credit and $400 million of short-term debt outstanding, leaving $1.88 billion available for liquidity purposes.

SCE’s estimated cash outflows during the 12-month period following March 31, 2008 are expected to consist of:

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

On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (2008 Stimulus Act). The 2008 Stimulus Act includes a provision that provides accelerated bonus depreciation for certain capital expenditures incurred during 2008. Edison International expects that certain capital expenditures incurred by SCE during 2008 will qualify for this accelerated bonus depreciation, which would provide additional cash flow benefits estimated to be approximately $175 million for 2008. Any cash flow benefits resulting from this accelerated depreciation should be timing in nature and therefore should result in a higher level of accumulated deferred income taxes reflected on SCE’s consolidated balance sheets. Timing benefits related to deferred taxes will be incorporated into future ratemaking proceedings, impacting future period cash flow and rate base.

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 2007 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 generation assets. SCE’s 2008 through 2012 capital forecast includes total spending of up to $19.9 billion, including capital spending of $875 million for SCE’s Solar PV Program. As discussed in “SCE: Current Developments—Solar Photovoltaic Program,” SCE filed an application with the CPUC to implement its Solar PV Program to develop up to 250 MW of utility-owned Solar PV generating facilities. During the first quarter of 2008, SCE spent $569 million in capital expenditures related to its 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, 2008, SCE’s 13-month weighted-average common equity component of total capitalization was 50.4% resulting in the capacity to pay $295 million in additional dividends.

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, 2008, 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. During the first quarter of 2008, SCE implemented FIN 39-1 and elected the option to net collateral with the fair value of derivative assets/liabilities under master netting arrangements. Amount recognized for cash collateral received from others that have been offset against net derivative assets totaled $4 million at March 31, 2008. In addition, at March 31, 2008, SCE had deposits of $253 million (consisting of $36 million in cash that was not offset against net derivative positions and was reflected in “Margin and collateral deposits” on the consolidated balance sheets and $217 million in letters of credit) with counterparties and other brokers. Cash deposits with brokers and counterparties earn interest at various rates.

Future cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2008, if wholesale energy prices decrease. SCE estimates that margin and collateral requirements for energy contracts outstanding as of March 31, 2008, could increase by approximately $555 million over the remaining life of the contracts using a 95% confidence level.

The credit risk exposure from counterparties for power and gas trading activities are measured as the difference between the contract price and current fair value of open positions. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE’s credit risk exposure from counterparties is based on a net exposure under these arrangements. At March 31, 2008, the amount of exposure as described above, broken down by the credit ratings of SCE’s counterparties, was as follows:

SCE has structured transactions (tolling contracts) in which SCE purchases all of the output of a plant from the counterparty. SCE’s structured transactions may be for multiple years which increases the volatility of the fair value position of the transaction. A number of the counterparties with which SCE has structured transactions do not currently have an investment grade rating or are below investment grade. SCE seeks to mitigate this risk through diversification of its structured transactions, when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from contracts.

SCE requires that counterparties with below investment grade ratings or those that do not currently have an investment grade rating post collateral. In the event of default by the counterparty, SCE would be able to use that collateral to pay for the commodity purchased or to pay the associated obligation in the event of default by the counterparty. Furthermore, all of the contracts that SCE has entered into with counterparties are entered into under SCE’s short-term and long-term procurement plan which has been approved by the CPUC. As a result, SCE would qualify for regulatory recovery for any defaults by counterparties on these transactions. In addition, SCE subscribes to rating agencies and various news services in order to closely monitor any changes that may affect the counterparties’ ability to perform.

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

The following table summarizes SCE’s system average rates, including the portion related to CDWR which is not recognized as revenue by SCE, at various dates in 2007 and 2008:

The March 2008 rate change resulted from increasing the FERC jurisdictional base transmission rates to include adopted CWIP incentives. See “—FERC Construction Work in Progress Mechanism” for further discussion. The

April 2008 rate change consolidated all of the 2008 authorized CPUC jurisdictional revenue requirements into rate levels. This decrease was primarily related to an increase in estimated 2008 kWh sales which more than offset a small increase in 2008 CPUC authorized revenue requirements.

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—2009 General Rate Case Proceeding” in the year-ended 2007 MD&A, SCE filed its GRC application on November 19, 2007. The application requests a 2009 base rate revenue requirement of $5.199 billion, an increase of approximately $858 million over the projected authorized base rate revenue requirements. After considering the effects of sales growth and other offsets, SCE’s request would be a $726 million increase over current authorized base rate revenue. If the CPUC approves these requested increases and allocates them to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 16.2% and 6.2%, respectively. SCE’s application also proposes a post-test year ratemaking mechanism which would result in 2010 and 2011 base rate revenue requirement increases, net of sales growth, of $216 million and $287 million, respectively. On April 15, 2008, the DRA submitted testimony recommending that SCE’s 2009 base rate revenue requirement be increased by approximately $7 million, a difference of $719 million from SCE’s request. The $719 million difference is mainly due to reductions proposed by DRA including: recommended changes in methods for calculating depreciation expense estimates resulting in a reduction of approximately $133 million; a reduction in transmission and distribution and generation operations and maintenance expense of approximately $167 million; a reduction in pensions and benefits of approximately $108 million; the elimination of results sharing as well as a reduction in long-term incentives and other executive compensation totaling approximately $141 million; and other miscellaneous proposed reductions. Testimony submitted by TURN, another intervenor, seeks to reduce SCE’s 2009 request by an additional $195 million over the DRA adjustments, due to a further reduction in depreciation expenses of approximately $125 million. In addition, TURN intends to propose additional adjustments related to the treatment of Mohave, replaced meters, software costs and other operating revenue sharing mechanisms. These issues will be the subject of evidentiary hearings scheduled in June 2008. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted although a final decision is expected prior to year-end.

As discussed under the headings “SCE: Regulatory Matters—FERC Transmission Incentives” and “—FERC Construction Work in Progress Mechanism” in the year-ended 2007 MD&A, on December 21, 2007, SCE filed a revision to its Transmission Owner Tariff to collect 100% of CWIP in rate base for its Tehachapi, DPV2, and Rancho Vista projects. In the CWIP filing, SCE proposed a single-issue rate adjustment ($45 million or a 14.4% increase) to SCE’s currently authorized base transmission revenue requirement to be made effective on March 1, 2008 and later adjusted for amounts actually spent in 2008 through a new balancing account mechanism. The rate adjustment represents actual expenditures from September 1, 2005 through November 30, 2007, projected expenditures from December 1, 2007 through December 31, 2008, and a ROE (which includes the ROE adders approved for Tehachapi, DPV2 and Rancho Vista). SCE projects that it will spend a total of approximately $244 million, $27 million, and $181 million for Tehachapi, DPV2, and Rancho Vista, respectively, from September 1, 2005 through the end of 2008. The 2008 DPV2 expenditure forecast is limited to projected consulting and legal costs associated with SCE’s continued efforts to obtain regulatory approvals necessary to construct the DPV2 Project. On February 29, 2008, the CWIP filing was approved and SCE implemented the CWIP rate on March 1, 2008, subject to refund on the limited issue of whether SCE’s proposed ROEs are reasonable. In the order, SCE was also directed by FERC to make a compliance filing to provide greater detail on the costs reflected in CWIP rates for 2008. SCE made the compliance filing on March 31, 2008. On April 21, 2008, the CPUC filed a protest of the compliance filing at FERC and requested an evidentiary hearing to be set to further review the costs. SCE intends to file a response to the CPUC’s protest, which rejects the CPUC’s request for a further hearing. In addition, on March 1, 2008, the CPUC filed a Petition for Rehearing with the FERC on the FERC’s acceptance of SCE’s proposed ROE for CWIP. SCE cannot predict the outcome of this proceeding.

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings” in the year-ended 2007 MD&A, the ERRA is the balancing account mechanism to track and recover SCE’s fuel and procurement-related costs. At March 31, 2008, the ERRA was overcollected by $293 million, which was 5.49% of SCE’s prior year’s generation revenue. The CPUC issued a decision on March 14, 2008 authorizing SCE to refund the over-collection to customers. SCE began refunding the over-collection in its consolidating rate change implemented on April 7, 2008. See “—Impact of Regulatory Matters on Customer Rates” for further discussion of SCE’s rate changes.

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Peaker Plant Generation Projects” in the year-ended 2007 MD&A, in response to a CPUC order, SCE pursued construction of five combustion turbine peaker plants, four of which were placed online in August 2007 to help meet peak customer demands and other system requirements.

SCE anticipates submitting updated testimony in connection with its December 2007 cost recovery application to revise the total recorded costs as of mid-2008 in the amount of approximately $248 million with projected costs of approximately $12 million. In its cost recovery application, SCE proposed to continue tracking the capital costs of the fifth peaker according to the interim cost tracking mechanism that was previously approved by the CPUC for all five peaker projects while they were in construction. Additionally, SCE proposed to file a separate cost recovery application for the fifth peaker after it is installed or its final disposition is otherwise determined. As of March 31, 2008, SCE has incurred capital costs of approximately $37 million for the fifth peaker. Several parties have filed protests or other filings in response to SCE’s application. SCE expects to fully recover its costs from these projects, but cannot predict the outcome of regulatory proceedings. SCE expects a CPUC decision on its cost recovery application in late 2008.

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Procurement of Renewable Resources” in the year-ended 2007 MD&A, 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.

As discussed under the heading “SCE: Regulatory Matters—FERC Refund Proceedings” in the year-ended 2007 MD&A, SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets during the energy crisis in

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

In May 2008, SCE and a number of other parties entered into a settlement of the FERC refund proceeding issues with NEGT Energy Trading-Power, L.P. (NEGT) and a related party, both of which are debtors in a Chapter 11 proceeding pending in the Maryland bankruptcy court. Under the terms of the settlement, NEGT will provide refunds valued at $66 million, a portion of which will be paid in the form of an allowed, unsecured claim in the Chapter 11 bankruptcy proceeding. SCE’s share of this amount is expected to be approximately $19 million. NEGT will also assign to SCE and the other parties to the settlement a corporate guarantee and surety bond that, subject to collection, will provide an additional $14 million. SCE’s share of the $14 million is yet to be determined. The settlement remains subject to the approvals of the Maryland bankruptcy court and FERC.

As discussed under the heading “SCE: Other Developments—Palo Verde Nuclear Generating Station Inspection” in the year-ended 2007 MD&A, the NRC held three special inspections of Palo Verde, between March 2005 and February 2007. The combination of the results of the first and third special inspections caused the NRC to undertake an additional oversight inspection of Palo Verde. This additional inspection, known as a supplemental inspection, was completed in December 2007. In addition, Palo Verde was required to take additional corrective actions based on the outcome of completed surveys of its plant personnel and self-assessments of its programs and procedures. The NRC and APS defined and agreed to inspection and survey corrective actions that the NRC in a Confirmatory Action Letter, which was issued in February 2008. Palo Verde operation and maintenance costs (including overhead) increased in 2007 by approximately $7 million from 2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in 2007 dollars) over the two year period 2008 – 2009, from 2007 recorded costs including overhead costs. SCE is unable to estimate how long SCE will continue to incur these costs.

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.

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used for liquidity purposes, to fund business operations and to finance capital expenditures.

In July 2007, SCE entered into interest rate-locks to mitigate interest rate risk associated with future financings. Due to declining interest rates in late 2007, at December 31, 2007, these interest rate locks had unrealized losses of $33 million. In January and February 2008, SCE settled these interest rate-locks resulting in realized losses of $33 million. A related regulatory asset was recorded in this amount and SCE expects to amortize and recover this amount as interest expense associated with its 2008 financings.

As discussed in the year-ended 2007 MD&A, SCE is exposed to commodity price risk associated with its purchases for additional capacity and ancillary services to meet its peak energy requirements as well as exposure

to natural gas prices associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including the Mountainview plant.

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

To mitigate SCE’s exposure to spot-market prices, SCE enters into energy options, tolling arrangements, forward physical contracts, and congestion rights (FTRs and CRRs). SCE also enters into contracts for power and gas options, as well as swaps and futures, in order to mitigate its exposure to increases in natural gas and electricity pricing. These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans.

In September 2007, the ISO allocated CRRs for the period March 2008 through December 2017 to SCE which will entitle SCE to receive (or pay) the value of transmission congestion at specific locations. These rights will act as an economic hedge against transmission congestion costs in the MRTU environment which was expected to be operational March 31, 2008, but was delayed to the fall of 2008. The CRRs meet the definition of a derivative under SFAS No. 133. In accordance with SFAS No. 157, SCE recognized the CRRs for the period beginning October 2008 at a zero fair value due to liquidity reserves. Liquidity reserves against CRRs fair values were provided since there were no quoted long-term market prices for the CRRs allocated to SCE. Although an auction was held in December 2007, the auction results did not provide sufficient evidence of long-term market prices.

During the first quarter of 2008, the ISO held an auction for FTRs. SCE participated in the ISO auction and paid $62 million to secure FTRs for the period April 2008 through March 2009. The FTRs will be replaced with CRRs in the MRTU environment. SCE recognized the FTRs for the period April 2008 through September 2008 at fair value. SCE anticipates amounts paid for FTRs for the period October 2008 through March 2009 will be refunded to SCE and has recognized this amount as a receivable from the ISO.

Any future fair value changes, given a MRTU market, will be recorded in purchased-power expense and offset through the provision for regulatory adjustments clauses as the CPUC allows these costs to be recovered from or refunded to customers through a regulatory balancing account mechanism. As a result, fair value changes are not expected to affect earnings.

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

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 implemented SFAS No. 157 during the first quarter of 2008. Under SFAS No. 157, when actual market prices, or relevant observable inputs are not available it is appropriate to use unobservable inputs which reflect management assumptions, including extrapolating limited short-term observable data and developing correlations between liquid and non-liquid trading hubs. The derivative assets and liabilities whose fair value is based on unobservable inputs are classified as level 3 measurements under SFAS No. 157. The amount of SCE’s level 3 derivative assets and liabilities measured using significant unobservable inputs as a percentage of the total derivative assets and total derivative liabilities measured at fair value was 61% and 100%, respectively. During the first quarter of 2008, the level 3 fair values increased as a result of changes in realized and unrealized gains. SCE recorded net realized and unrealized gains of $149 million and $105 million for the three months ended March 31, 2008 and 2007, respectively. The changes in net realized and unrealized gains on economic hedging activities were primarily due to higher forward natural gas prices in the first quarter of 2008, compared to the same period in 2007. Due to expected recovery through regulatory mechanisms unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings.

At March 31, 2008, EMG and its subsidiaries had cash and cash equivalents and short-term investments of $1.2 billion, EMG had a total of $937 million of available borrowing capacity under its credit facilities. EMG’s consolidated debt at March 31, 2008 was $4.0 billion. In addition, EME’s subsidiaries had $3.8 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 27 years.

At March 31, 2008, the estimated capital expenditures through 2010 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, railroad interconnection, replacement of major boiler components, mill inerting projects and ash site disposal development. Environmental expenditures relate to environmental projects such as mercury emission monitoring and control and a selenium removal system 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 fund these expenditures with debt financings, cash on hand or cash generated from operations. For further discussion regarding these and possible additional capital expenditures, including environmental control equipment at the Homer City facilities, refer to “Edison International: Management’s Overview,” and “Other Developments—Environmental Matters—Air Quality Regulation—Clean Air Interstate Rule—Illinois,” and “Other Developments—Environmental Matters—Air Quality Regulation—Mercury Regulation” in the year-ended 2007 MD&A.

EME expects to make substantial investments in new projects during the next several years. At March 31, 2008, EME had committed to purchase turbines (as reflected in the above table of capital expenditures) for wind projects that aggregate 1,076 MW. The turbine commitments generally represent approximately two-thirds of the total capital costs of EME’s wind projects. As of March 31, 2008, EME had a development pipeline of potential

wind projects with projected installed capacity of approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Completion of development of a wind project may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment. Furthermore, successful completion of a wind project is dependent upon obtaining permits, an interconnection agreement(s) or other agreements necessary to support an investment. There is no assurance that each project included in the development pipeline currently or added in the future will be successfully completed.

Credit ratings for EMG’s direct and indirect subsidiaries at March 31, 2008, were as follows:

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

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

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

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

grade, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to accounts payable and unrealized losses in connection with these hedging and trading activities. At March 31, 2008, EMMT had deposited $32 million in cash with brokers in margin accounts in support of futures contracts and had deposited $79 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $17 million in support of commodity contracts at March 31, 2008.

Future cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2008, 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, 2008 could increase by approximately $470 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, 2008, Midwest Generation had available $422 million of borrowing capacity under this credit facility. As of March 31, 2008, Midwest Generation had $105 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and $515 million of borrowing capacity available under a $600 million working capital facility to provide credit support to subsidiaries.

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 at March 31, 2008 or for the 12 months ended March 31, 2008:

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, 2008.

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—Dividend Restrictions in Major Financings” in the year-ended 2007 MD&A.

On April 4, 2008, the FERC issued an order rejecting PJM’s request to revise its RPM to reflect PJM’s claimed rise in its CONE values. CONE is one of the two components used by PJM to determine its Variable Resource Requirement curve for the RPM auction. PJM also proposed to add a new section to its tariff permitting PJM to unilaterally request a CONE increase for use in its May 2008 RPM auction for the 2011/2012 delivery year. In rejecting the proposal, the FERC found that PJM had not met timing provisions in its existing tariff to provide sufficient time for stakeholder review of the analysis and advance planning and that it had also failed to establish that its proposal to revise that provision was necessary on a one-time emergency basis to ensure reliable service.

The effect of FERC’s actions on future RPM auctions cannot be determined at this time. The CONE as established for the May 2008 RPM auction for the 2011/2012 delivery year is lower than the PJM request.

EMG’s primary market risk exposures are associated with the sale of electricity and capacity from and the procurement of fuel for EME’s merchant power plants. These market risks arise from fluctuations in electricity, capacity and fuel prices, emission allowances, and transmission rights. Additionally, EME’s financial results can be affected by fluctuations in interest rates. EME manages these risks in part by using derivative financial instruments in accordance with established policies and procedures.

EME’s 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 “earnings at risk” to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions of the Illinois plants, the Homer City facilities, and the merchant wind projects, and “value at risk” to identify, measure, monitor and control its overall risk exposure in respect of its trading positions. The use of these measures 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, and earnings at risk measures the potential change in value of an asset or position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches 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 hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine whether the types of hedge transactions set forth above at forward market prices are sufficiently attractive compared to assuming the risk associated with fluctuating spot market sales. Second, EME’s ability to enter into hedging transactions depends upon its and Midwest Generation’s credit capacity and upon the forward sales markets having sufficient liquidity to enable EME to identify appropriate counterparties for hedging transactions.

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

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

Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to the generation of the Illinois plants are generally entered into at the Northern Illinois Hub in PJM, and may also be entered into at other trading hubs, including the AEP/Dayton Hub in PJM and the Cinergy Hub in the Midwest Independent Transmission System Operator. These trading hubs have been the most liquid locations for hedging purposes. 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 2008 and 2007.

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, 2008:

The following table summarizes Midwest Generation’s hedge position (primarily based on prices at the Northern Illinois Hub) at March 31, 2008:

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 2008 and 2007:

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, 2008:

The following table summarizes EME Homer City’s hedge position at March 31, 2008:

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

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

The following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at March 31, 2008:

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

Midwest Generation entered into hedge transactions in advance of the RPM auctions with counterparties that are settled through PJM. In addition, the load service requirements contracts entered into by Midwest Generation with Commonwealth Edison include energy, capacity and ancillary services (sometimes referred to as a “bundled product”). Under PJM’s business rules, Midwest Generation sells all of its available capacity (defined as unit capacity less forced outages) into the RPM and is subject to a locational reliability charge for the load under these contracts. This means that the locational reliability charge generally offsets the related amounts sold in the RPM, which Midwest Generation presents on a net basis in the table above.

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

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 revenues with respect to such forward contracts include:

Under PJM’s market design, locational marginal pricing, which establishes market prices at specific locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by transmission constraints. Effective June 1, 2007, PJM implemented marginal losses which adjust the algorithm that calculates locational marginal prices to include a component for marginal transmission losses in addition to the component included for congestion. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as “basis risk.” During the three months ended March 31, 2008 and 2007, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 12% and 11%, respectively. The monthly average difference during the 12 months ended March 31, 2008 ranged from 7% to 24%. In contrast to the Homer City facilities, during the past 12 months, the prices at the

Northern Illinois Hub were substantially the same as those at the individual busbars of the Illinois plants, although the implementation of marginal losses on June 1, 2007 has lowered energy prices at the Illinois plants busbars.

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

The Illinois plants and the Homer City facilities purchase coal primarily obtained from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements extending through 2011. The following table summarizes the amount of coal under contract at March 31, 2008 for the remainder of 2008 and the following three years.

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian coal, which are related to the price of coal purchased for the Homer City facilities, increased substantially during the first quarter of 2008 from 2007 year-end prices. The price of Northern Appalachian coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO₂ per MMBtu sulfur content) increased to $110.00 per ton at March 28, 2008 from $55.25 per ton at December 21, 2007, as reported by the Energy Information Administration. Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO₂ per MMBtu sulfur content) purchased for the Illinois plants increased during the first quarter of 2008 from 2007 year-end prices. The price of PRB coal increased to $14.55 per ton at March 28, 2008 from $11.50 per ton at December 21, 2007, as reported by the Energy Information Administration. The 2008 increases in coal prices were primarily attributable to: 1) increased Asian coal demand primarily driven by China and India, 2) port and rail infrastructure problems and monsoon flooding in Australia, 3) a record cold winter in China, and 4) an energy crisis in South Africa.

EME has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers), which extends through 2011. EME is exposed to price risk related to higher transportation rates after the expiration of its existing transportation contracts. Current transportation rates for PRB coal are higher than the existing rates under contract (transportation costs are more than 50% of the delivered cost of PRB coal to the Illinois plants).

The federal Acid Rain Program requires electric generating stations to hold SO₂ allowances, and Illinois and Pennsylvania regulations implemented the federal NO_X SIP Call requirement. As part of the acquisition of the Illinois plants and the Homer City facilities, EME obtained the rights to the emission allowances that have been

or are allocated to these plants. EME purchases (or sells) emission allowances based on the amounts required for actual generation in excess of (or less than) the amounts allocated under these programs.

The average price of purchased SO₂ allowances decreased to $343 per ton during the first quarter of 2008 from $512 per ton during 2007. The price of SO₂ allowances, determined by obtaining broker quotes and information from other public sources, was $340 per ton as of March 31, 2008.

For a discussion of environmental regulations related to emissions, refer to “Other Developments—Environmental Matters” in the year-ended 2007 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, refer to “Critical Accounting Estimates and Policies—Derivative Financial Instruments and Hedging Activities” in the year-ended 2007 MD&A.

SFAS No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies under SFAS No. 133 from accrual accounting (i.e., revenue recognition based on settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from energy contracts as part of operating revenues. The results of derivative activities are recorded as part of cash flows from operating activities in the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities for the first quarters of 2008 and 2007:

At March 31, 2008, unrealized losses of $45 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($26 million for the remainder of 2008, $14 million for 2009, and $5 million for 2010).

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 quoted market prices and forward market prices adjusted for credit risk. 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, 2008 as compared to December 31, 2007 is attributable to an increase in the average market prices for power as compared to contracted prices at March 31, 2008, 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, 2008:

Prices actively quoted in the preceding table includes derivatives whose fair value is based on quoted market prices and forward market prices adjusted for credit risk.

The fair value of the commodity financial instruments related to energy trading activities as of March 31, 2008 and December 31, 2007, are set forth below:

The change in the fair value of trading contracts for the quarter ended March 31, 2008, was as follows:

EME adopted SFAS No. 157 effective January 1, 2008. The standard established a hierarchy for fair value measurements.

In the table below, prices actively quoted includes both exchange traded derivatives and non-exchange traded derivatives which are priced based on forward market prices adjusted for credit risk. Also in the table, fair value

based on models and other valuation methods includes illiquid FTRs and over-the-counter derivatives at illiquid locations and long-term power agreements which would be considered Level 3 derivative positions. For illiquid FTRs, EME determines fair value based on the hypothetical sale of illiquid positions. For long-term power agreements, EME’s subsidiary recorded these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit and liquidity.

The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of March 31, 2008):

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, 2008, 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 revenues for the three months ended March 31, 2008. Moody’s rates PJM’s senior unsecured debt Aa3. PJM, an independent system operator 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, 2008, EME’s account receivable due from PJM was $100 million.

EME also derived a significant source of its revenues 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 16% of EME’s consolidated operating revenues during the three months ended March 31, 2008. Commonwealth Edison’s senior unsecured debt ratings are BBB- by S&P and Ba1 by Moody’s. At March 31, 2008, EME’s account receivable due from Commonwealth Edison was $17 million. For the three months ended March 31, 2008, a third customer accounted for 11% of EME’s consolidated operating revenues.

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.

At March 31, 2008, Edison Capital had a net leveraged lease investment, before deferred taxes, of $53 million in three aircraft leased to American Airlines. American Airlines has reported net losses for its first quarter 2008 and previously reported 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, 2008, American Airlines was current in its lease payments to Edison Capital.

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EMG 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 EMG’s consolidated long-term obligations (including current portion) was $3.99 billion at March 31, 2008, compared to the carrying value of $4.02 billion.

Edison Capital holds a minority interest as a limited partner in three separate funds that invest in infrastructure assets in Latin America, Asia and countries in Europe with emerging economies. As of March 31, 2008, Edison Capital had investments in Latin America, Asia and Emerging Europe of $20 million, $18 million and $18 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 currency 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, 2008, Edison International (parent) had no debt outstanding (excluding intercompany related debt).

Edison International (parent)’s cash requirements for the 12-month period following March 31, 2008 are expected to consist of:

Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand, borrowings and dividends and/or borrowings from its subsidiaries. At March 31, 2008, Edison International (parent) had approximately $75 million of cash and cash equivalents on hand. On March 12, 2008, Edison International (parent) amended its existing $1.5 billion credit facility, extending the maturity to February 2013 while retaining existing borrowing costs as specified in the facility. The amendment also provides four extension options which, if all exercised, will result in a final termination of February 2017. At March 31, 2008, the entire credit facility was available for liquidity purposes. The ability of subsidiaries to make dividend payments to Edison International is dependent on various factors as described below.

SCE may pay dividends to Edison International subject to CPUC restrictions. The CPUC regulates SCE’s capital structure by requiring that SCE maintain prescribed percentages of common equity, preferred equity and long-term debt in the utility’s capital structure. SCE may not make any distributions to Edison International that would reduce the common equity component of SCE’s capital structure below the authorized level on a 13-month weighted average basis (see “SCE: Liquidity—Dividend Restrictions and Debt Covenants” for further discussion). The CPUC also requires that SCE establish its dividend policy as though it were a comparable stand-alone utility company and give first priority to the capital requirements of the utility as necessary to meet its obligation to serve its customers. Other factors at SCE that affect the amount and timing of dividend payments by SCE to Edison International include, among other things, SCE’s capital requirements, SCE’s access to capital markets, payment of dividends on SCE’s preferred and preference stock, and actions by the CPUC. The Board of Directors of SCE declared a $25 million dividend which was paid in January 2008 and a $100 million dividend which was paid in April 2008.

EMG’s ability to pay dividends is dependent on its subsidiaries’ ability to pay dividends to EMG. EME’s corporate credit facility contains covenants that restrict its ability, and the ability of several of its subsidiaries, to pay dividends in the case of any event of default under the facility. As of March 31, 2008, EME was not in default under its credit facility. In addition, see “EMG: Liquidity—Dividend Restrictions in Major Financings” for further discussion. Edison Capital loaned $120 million to Edison International in January 2008 (total outstanding as of March 31, 2008 is $170 million).

The following sections of the MD&A are on a consolidated basis and should be read in conjunction with the 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 for the three months ended March 31, 2008 and 2007, and the relative contributions by its subsidiaries.

Edison International’s first quarter 2008 earnings from continuing operations were $304 million, compared to $330 million in 2007.

SCE’s earnings from continuing operations were $150 million in 2008, compared with earnings of $180 million in 2007. The decrease was mainly due to a $31 million tax benefit recognized in 2007 related to the income tax treatment of certain costs including those associated with environmental remediation, partially offset by lower net interest expense in 2008.

EMG’s earnings from continuing operations were $159 million in 2008, compared with earnings of $155 million in 2007. The increase primarily reflects higher gross margin and the buyout of a coal contract at EMG’s Illinois plants together with higher energy trading results. These increases were partially offset by lower earnings from Edison Capital and other generation projects together with higher costs associated with EMG’s growth activities.

SCE’s retail sales represented approximately 85% and 88% of electric utility revenue for the three months ended March 31, 2008 and 2007, respectively. Due to warmer weather during the summer months and SCE’s rate design, electric utility revenue during the third quarter of each year is generally higher than other quarters.

Total electric utility revenue increased by $127 million in the first quarter of 2008 compared to the same period in 2007 (as shown in the table above). The variances for the revenue components are as follows:

Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE’s customers, CDWR bond-related costs and a portion of direct access exit fees are remitted to the CDWR and none of these collections are recognized as revenue by SCE. These amounts were $558 million and $587 million for the three months ended March 31, 2008 and 2007, respectively.

The following table sets forth the major components of nonutility power generation revenue:

Nonutility power generation revenue increased $47 million in the first quarter of 2008 compared to the same period in 2007.

Nonutility power generation revenue from EMG’s Illinois plants increased $37 million for the first quarter of 2008, compared to the first quarter of 2007. The increase was primarily attributable to higher energy and capacity prices due to higher market prices and lower unrealized losses in 2008 related to hedge contracts described below. Partially offsetting this increase was lower generation in 2008 due to unplanned outages.

EMG’s Illinois plants recorded unrealized losses of $5 million and $22 million for the first quarters of 2008 and 2007, respectively. Unrealized losses are primarily due to power contracts that did not qualify for hedge accounting under SFAS No. 133 (sometimes referred to as economic hedges). These energy contracts were entered into to hedge the price risk related to projected sales of power. During 2008, power prices increased, resulting in mark-to-market losses on economic hedges. At March 31, 2008, unrealized losses of $23 million were recognized from economic hedges and from the ineffective portion of cash flow hedges related to subsequent periods. The ineffective portion of hedge contracts at the Illinois plants was primarily attributable to changes in the difference between energy prices at NiHub (the settlement point under forward contracts) and the energy prices at the Illinois plants busbars (the delivery point where power generated by the Illinois plants is delivered into the transmission system) resulting from marginal losses. See “EMG: Market Risk Exposures—Commodity Price Risk” for more information regarding forward market prices.

Nonutility power generation revenue from EMG’s Homer City facilities decreased $13 million for the first quarter of 2008, compared to the first quarter of 2007. The 2008 decrease was primarily attributable to lower operating revenue attributable to lower average realized energy prices and lower generation (particularly off-peak) as compared to 2007. Higher forced outages in 2008 contributed to lower generation.

EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel and transmission congestion primarily in the eastern power grid using products available over the counter, through exchanges and from independent system operators. Nonutility power generation revenue from energy trading activities at EMMT increased $15 million for the first quarter of 2008,

compared to the first quarter of 2007. The increase in nonutility power generation revenue from energy trading activities was primarily attributable to higher revenue from energy trading in the over-the-counter markets and power sales into New York.

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

SCE’s fuel expense increased $40 million in the first quarter of 2008 mainly due to an increase at SCE’s Mountainview plant resulting from higher generation and higher gas costs in 2008 due to an outage that occurred in the first quarter of 2007.

EMG’s fuel expense increased $11 million in the first quarter of 2008 mainly due to higher coal and transportation costs per megawatt hour at EMG’s Illinois plants mainly due to cost escalations included in the transportation contracts.

Total purchased-power expense increased $174 million in 2008 based on the components discussed below.

Purchased power, in the table above, increased $189 million in the first quarter of 2008 due to higher bilateral energy purchases of $45 million resulting from higher costs per kWh due to higher gas prices and increased kWh purchases from new contracts entered into in late 2007; higher QF purchased-power expense of $60 million

resulting from increased kWh purchases and an increase in the average spot natural gas prices for certain contracts (as discussed further below); and higher ISO-related energy costs of $85 million.

Net realized and unrealized gains on economic hedging activities, in the table above, was $149 million in the first quarter of 2008 compared to $105 million in the same period in 2007 (see “SCE: Market Risk Exposures—Commodity Price Risk” for further discussion). The changes in net realized and unrealized (gains) losses on economic hedging activities were primarily due to higher forward natural gas prices in the first quarter of 2008, compared to the same period in 2007. Due to expected recovery through regulatory mechanisms realized and unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings (see “SCE: Market Risk Exposures—Commodity Price Risk” for further discussion).

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

Provisions for regulatory adjustment clauses – net decreased $117 million in the first quarter of 2008 compared to the same period in 2007. The first quarter 2008 variance reflects net unrealized gains on economic hedging activities of approximately $151 million in 2008, compared to $134 million for the same period in 2007 (discussed above in purchased-power expense). The 2008 variance also reflects a decrease of $60 million as a result of the rate reduction notes being fully repaid as of December 31, 2007 (See “SCE: Liquidity—Rate Reduction Notes” in the year-ended 2007 MD&A); approximately $29 million in energy refunds and generator settlements recorded in 2007; higher FTR costs of $35 million; and approximately $30 million resulting from higher net undercollections primarily related to the deferral of the residential rate increase which was recognized in revenue in 2007.

SCE’s other operation and maintenance expense increased $84 million in the first quarter of 2008 compared to the first quarter of 2007. Certain of SCE’s operation and maintenance expense accounts are recovered through regulatory mechanisms approved by the CPUC. The costs associated with these regulatory balancing accounts increased $10 million in the first quarter of 2008. In addition to the increase in balancing account related operation and maintenance costs the 2008 increase was due to higher generation expenses of $20 million related to maintenance and outage expenses at San Onofre and higher overhaul and outage costs at Four Corners and Palo Verde; transmission and distribution maintenance cost of approximately $15 million; and higher administrative and general costs (including health care costs and other benefits) of $20 million primarily due to timing of expenses.

EMG’s other operation and maintenance expense increased $10 million in the first quarter of 2008, compared to the first quarter of 2007. The 2008 increase was mainly due to higher labor costs and consulting expense resulting from EME’s growth activities.

SCE’s depreciation, decommissioning and amortization expense decreased $23 million in the first quarter of 2008 compared to the same period in 2007 due to a $40 million decrease in nuclear decommissioning trust earnings and higher other-than-temporary impairment losses associated with the nuclear decommissioning trust funds primarily related to a volatile stock market environment. Due to its regulatory treatment, investment impairment losses and trust earnings and losses are recorded in electric utility revenue and are offset in decommissioning expense and have no impact on net income. The decrease was partially offset by a $20 million increase resulting from transmission and distribution asset additions (see “SCE: Liquidity—Capital Expenditures” for a further discussion).

EMG’s depreciation and amortization expense increased $8 million in the first quarter of 2008 compared to the same period in 2007. The 2008 increase was primarily attributable to higher depreciation expense for wind projects.

Gain on buyout of contract and sale of assets increased $17 million primarily related to a gain of $15 million recorded in 2008 related to the buyout of a fuel contract (see “Commitments, Guarantees and Indemnities—Fuel Supply Contracts” for further discussion).

In March 2008, First Energy exercised an early buyout right under the terms of an existing lease agreement with Edison Capital related to Unit No. 2 of the Beaver Valley Nuclear Power Plant. The exercise price is equal to the greater of a fixed amount and fair market value. The termination date of the lease under the early buy out option is June 1, 2008. Based on the fixed amount, the cash proceeds and net income from the termination of the lease (second quarter 2008) is estimated to be $68 million and $20 million, respectively.

SCE’s interest income decreased $5 million in the first quarter of 2008, compared to the first quarter of 2007. The 2008 decrease was mainly due to lower undercollections balances in certain balancing accounts and lower interest rates applied to those undercollections in the first quarter of 2008, as compared to the same period in 2007.

EMG’s interest and dividend income decreased $21 million in the first quarter of 2008 compared to the first quarter of 2007. The 2008 decrease was primarily attributable to lower average short-term investment balances and lower interest rates in 2008 compared to 2007.

Equity in income from partnerships and unconsolidated subsidiaries – net decreased $15 million in the first quarter of 2008 compared to the first quarter of 2007 mainly due to gains from Edison Capital’s global infrastructure funds recorded in the first quarter of 2007.

EMG’s other nonoperating income increased $6 million in the first quarter of 2008. The 2008 increase is due to estimated insurance recoveries for EMG’s Illinois plants related to the Powerton Station outage claims on property and business interruption insurance policies of approximately $6 million recorded in 2008. On December 18, 2007, Unit 6 at the Powerton Station had a duct failure resulting in a suspension of operations at this unit through February 12. Scheduled maintenance work for the spring of 2008 was accelerated to minimize the aggregate impact of the outage.

SCE’s interest expense – net of amounts capitalized decreased $10 million in the first quarter of 2008 mainly due to lower overcollections of certain balancing accounts and lower interest rates applied to those overcollections in the first quarter of 2008 compared to the same period in 2007. The decrease was also due to lower interest expense on long-term debt resulting from lower outstanding debt during the first quarter of 2008 compared to the first quarter 2007.

EMG’s interest expense – net of amounts capitalized decreased $18 million in the first quarter of 2008 compared to the first quarter of 2007. The 2008 decrease was primarily attributable to MEHC’s redemption in full of its senior secured notes in June 2007. The variances are also attributable to $2.7 billion of new debt entered into by EME as part of its refinancing activities in May 2007 (See “EMG: Liquidity—EMG Financing Developments” in the year-ended 2007 MD&A).

Edison International’s composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. Edison International’s effective tax rate from continuing operations was 35% for the three months ended March 31, 2008, as compared to 28% for the respective period in 2007. The increased effective tax rate was caused primarily by the reductions to the income tax reserve recorded in the first quarter of 2007 to reflect progress in an administrative appeals process with the IRS related to SCE’s income tax treatment of costs associated with environmental remediation.

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

Minority interest decreased $11 million as a result of lower earnings related to two of SCE’s VIEs mainly due to lower pricing and a planned outage in 2008 at another one of SCE’s VIEs. Earnings from two of SCE’s VIEs (the Sycamore project and the Watson project) are based on revised pricing effective January 1, 2008. Watson Cogeneration and SCE have disputed the commencement date of the prior contract which in turn affected the expiration date (Watson Cogeneration’s position is April 2008 whereby SCE’s position is December 2007). See “Market Risk Exposures—Big 4 Projects Power Purchase Agreements” in the year-ended 2007 MD&A for further discussion.

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

Cash provided by operating activities from continuing operations decreased $152 million in 2008, compared to 2007. The 2008 change reflects a decrease in revenue collected from SCE’s customers primarily due to the rate change that was effective February 14, 2007. On February 14, 2007, SCE’s system average rate decreased from 14.5¢ per-kWh to 13.9¢ per-kWh. See “SCE: Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates,” and “—Energy Resource Recovery Account Proceedings” for further discussion of rate changes. The 2008 change was also due to the timing of cash receipts and disbursements related to working capital items including lower income taxes paid in 2008 compared to 2007.

Cash provided (used) by financing activities from continuing operations mainly consisted of long-term debt issuances (payments) at SCE and EMG and dividends paid by Edison International to its common shareholders.

Cash flows from investing activities are affected by capital expenditures, SCE’s funding of nuclear decommissioning trusts, and proceeds and maturities of investments.

Investing activities in 2008 reflect $588 million in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $19 million for nuclear fuel acquisitions, and $117 million in capital expenditures at EMG. Investing activities also include net maturities and sales of short-term investments of $46 million and net purchases of nuclear decommissioning trust investments and other of $30 million.

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 and net purchases of nuclear decommissioning trust investments and other of $33 million.

In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s

financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. Edison International will adopt SFAS No. 161 in the first quarter of 2009. SFAS No. 161 will impact disclosures only and will not have an impact on Edison International’s consolidated results of operations, financial condition or cash flows.

The following is an update to Edison International’s commitments, guarantees and indemnities. See the section, “Commitments, Guarantees and Indemnities” in the year-ended 2007 MD&A for a detailed discussion.

In connection with the acquisition of the Illinois plants, Midwest Generation had assumed a long-term coal supply contract and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buy out its coal obligations for the years 2009 through 2012 under this contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million, after tax) during the first quarter of 2008. The remaining payments due under this contract are $20 million.

At March 31, 2008, EME had entered into agreements with vendors securing 483 wind turbines (1,076 MW) for an aggregate purchase price of $1.3 billion with remaining commitments of $474 million in 2008, $540 million in 2009 and $49 million in 2010. At March 31, 2008, EME had recorded wind turbine deposits of $197 million included in other long-term assets in its consolidated balance sheet. In addition, EME had 30 wind turbines (90 MW) in temporary storage to be used for future wind projects with remaining commitments of $3 million in 2008. At March 31, 2008, EME had recorded $84 million related to these wind turbines included in other long-term assets in its consolidated balance sheet.

At March 31, 2008, Edison International’s recorded net liability for uncertain tax positions was $460 million. Edison International currently cannot reliably predict the timing of cash flows associated with the resolution of uncertain tax positions due to the uncertainty as to the timing for resolving tax issues with the IRS related to ongoing examinations and administrative appeals. See “Other Developments—Federal and State Income Taxes” for further information.

The operating subsidiaries 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 subsidiaries are in substantial compliance with existing environmental regulatory requirements. However, the US EPA has issued a NOV to Midwest Generation and Commonwealth Edison, the former owner of Midwest Generation’s coal-fired power plants, alleging violations of the CAA and certain opacity and particulate matter standards. For information on the US EPA NOV issued to Midwest Generation, see “EMG: Other Developments—Midwest Generation Potential Environmental Proceeding” in the year-ended 2007 MD&A.

The domestic power plants owned or operated by Edison International’s operating subsidiaries, 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. The developments in certain of these laws and regulations are discussed in more detail below. These developments will continue to be monitored to assess what implications, if any, they will have on the operation of domestic power plants owned or operated by SCE, EME, or their subsidiaries, or the impact on Edison International’s consolidated results of operations or financial position.

Edison International’s projected environmental capital expenditures over the next five years are: 2008 –$531 million; 2009 – $544 million; 2010 – $749 million; 2011 – $513 million; and 2012 – $526 million. The projected environmental capital expenditures are mainly for undergrounding certain transmission and distribution lines at SCE and upgrading environmental controls at EME.

For a discussion of Edison International’s environmental matters, refer to “Other Developments—Environmental Matters” in the year-ended 2007 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 February 28, 2008, the Native Village of Kivalina and the City of Kivalina, located off the coast of Alaska, filed a complaint in federal court in California against 23 corporate defendants, including Edison International and several electric generating, oil and gas, and coal mining companies. The complaint contends that the alleged global warming impacts of the GHG emissions associated with the defendants’ business activities are destroying the plaintiffs’ village through the melting of Arctic ice that had previously protected the village from winter storms. The plaintiffs further allege that the village will soon need to be abandoned or relocated at a cost of between $95 million and $400 million. Edison International cannot predict the outcome of this litigation.

SCE and EME are evaluating the CARB’s reporting regulations adopted December 2007 pursuant to AB 32 to assess the total cost of compliance.

In mid-March 2008, the CEC and CPUC recommended that CARB adopt a mix of direct mandatory/regulatory requirements and a cap-and-trade system for the electricity sector as part of CARB’s AB 32 scoping plan for achieving the maximum technologically feasible and cost-effective reductions in greenhouse gas emissions by 2020. The recommendations include: a mandatory minimum levels of cost-effective energy efficiency for all retail electricity providers; legislation requiring all retail electricity providers to deliver more than 20% of their

power from renewable sources in the future, at levels and dates to be determined; a multi-sector cap-and-trade program for California that includes the electricity sector; CARB designation of deliverers of electricity to the California grid as the entities responsible for compliance with the AB 32 requirements; and the auction of at least some portion of the emission allowances available to the electricity sector for the cap-and-trade program. An integral part of this auction recommendation is that the majority of the proceeds from the auctioning of allowances for the electricity sector should be used in ways that benefit electricity consumers in California, such as to augment investments in energy efficiency and renewable energy or to provide customer bill relief.

CARB still must determine whether to adopt the CEC’s and CPUC’s recommendations as part of its AB 32 scoping plan. CARB is expected to release a draft AB 32 scoping plan in June 2008 for public review and comment. CARB is required to approve its AB 32 scoping plan by January 1, 2009.

On March 12, 2008, the US EPA signed a final rule that implements revisions to the primary and secondary national ambient air quality standards for ozone, originally proposed on July 11, 2007. With regard to the primary standard for ozone, the US EPA has reduced the 8-hour standard to 0.075 parts per million (ppm) from the current standard of 0.84 ppm. The rule is expected to become effective during the second quarter of 2008. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. Based on 2005-2007 data, Chicago is likely to be in non-attainment with the new standard. Available data indicates that the area in which the Homer City facilities are located is likely to be in attainment. EME intends to consider the new standards as part of its overall plan for environmental compliance.

On March 21, 2008 the California State Water Resources Control Board released its draft scoping document and preliminary draft Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling. This state policy is being developed in advance of the issuance of a final rule from the US EPA on standards for cooling water intake structures at existing large power plants. As anticipated, the Scoping Document establishes closed cycle wet cooling as the best technology available for retrofitting existing once-through cooled plants like San Onofre. Additionally, the target levels for compliance with the state policy correspond to the high end of the ranges originally proposed in the US EPA’s rule. Nuclear-fueled power plants, including San Onofre, would have until January 1, 2021 to comply with the policy. The tentative policy development schedule that was included in the Scoping Document schedules public workshops in May 2008 and a public hearing in September 2008. Policy adoption would tentatively be voted on by the State Board in December 2008. SCE is currently evaluating potential effects of the policy and working with key government policy makers. This policy may significantly impact both operations at San Onofre and SCE’s ability to procure timely supplies of generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems.

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.

Tax Positions being addressed as part of active examinations and administrative appeals processes

As of March 31, 2008, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $557 million. The IRS has also asserted a 20% penalty on any sustained tax adjustment.

The payment of taxes, interest and penalties could have a significant impact on earnings and cash flow. Edison International is prepared to take legal action if an acceptable settlement cannot be reached with the IRS. If Edison International were to commence litigation in certain forums, Edison International would need to 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 recorded in “Other long-term assets” on the consolidated balance sheet and 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 which provides Edison International with the option of being able to take legal action to assert its refund claim.

additional payments is uncertain, the amount of additional payments, if necessary, could be substantial. At this time, Edison International is unable to predict the impact of the ultimate resolution of the lease issues.

Resolution of Federal and State Income Tax Issues Being Addressed in Ongoing Examinations and Administrative Appeals

As discussed under the heading “Other Developments—Midway-Sunset Cogeneration Company” in the year-ended 2007 MD&A, Midway-Sunset is a party to several proceedings pending at the FERC because Midway-Sunset was a seller in the PX market during 2000 and 2001, both for its own account and on behalf of SCE and PG&E, the utilities to which the majority of Midway-Sunset’s power was contracted for sale.

Edison International does not expect any refund payment to be made by Midway-Sunset, or any SCE reimbursement to Midway-Sunset, to have a material impact on earnings.

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 May 6, 2008
Common Stock, no par value		325,811,206


		Page No.
Part I. Financial Information

Item 1.	Financial Statements:	1

	Consolidated Statements of Income – Three Months Ended March 31, 2008 and 2007	1

	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2008 and 2007	2

	Consolidated Balance Sheets – March 31, 2008 and December 31, 2007	3

	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2008 and 2007	5

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	83

Item 4.	Controls and Procedures	83

Part II. Other Information

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	84

Item 6.	Exhibits	85

Signature		86


Midwest Generation		Midwest Generation, LLC
MMBtu		million British thermal units
Mohave		Mohave Generating Station
Moody’s		Moody’s Investors Service
MRTU		Market Redesign Technology Upgrade
MW		megawatts
MWh		megawatt-hours
NOV		notice of violation
NO_x		nitrogen oxide
NRC		Nuclear Regulatory Commission
NYISO		New York Independent System Operator
Palo Verde		Palo Verde Nuclear Generating Station
PBOP(s)		postretirement benefits other than pension(s)
PBR		performance-based ratemaking
PG&E		Pacific Gas & Electric Company
PJM		PJM Interconnection, LLC
POD		Presiding Officer’s Decision
PRB		Powder River Basin
PX		California Power Exchange
QF(s)		qualifying facility(ies)
RICO		Racketeer Influenced and Corrupt Organization
ROE		return on equity
RPM		reliability pricing model
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. 133		Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
SFAS No. 141(R)		Statement of Financial Accounting Standards No. 141(R), Business Combinations
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 Financial Liabilities
SFAS No. 160		Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements
SFAS No. 161		Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133”
SIP(s)		State Implementation Plan(s)
SO₂		sulfur dioxide
TURN		The Utility Reform Network
US EPA		United States Environmental Protection Agency
VIE(s)		variable interest entity(ies)


	Three Months Ended March 31,
In millions, except per-share amounts	2008			2007
	(Unaudited)
Electric utility	$	2,349		$	2,222
Nonutility power generation		719			672
Financial services and other		15			18
Total operating revenue		3,083			2,912
Fuel		537			486
Purchased power		491			317
Provisions for regulatory adjustment clauses – net		172			289
Other operation and maintenance		974			880
Depreciation, decommissioning and amortization		298			313
Gain on buyout of contract and sale of assets		(17	)		—
Total operating expenses		2,455			2,285
Operating income		628			627
Interest and dividend income		14			39
Equity in income from partnerships and unconsolidated subsidiaries – net		2			17
Other nonoperating income		25			17
Interest expense – net of amounts capitalized		(171	)		(198	)
Other nonoperating deductions		(12	)		(11	)
Income from continuing operations before tax and minority interest		486			491
Income tax expense		161			129
Dividends on preferred and preference stock of utility not subject to mandatory redemption		13			13
Minority interest		8			19
Income from continuing operations		304			330
Income (loss) from discontinued operations – net of tax		(5	)		3
Net income	$	299		$	333
Weighted-average shares of common stock outstanding		326			326
Basic earnings (loss) per common share:
Continuing operations	$	0.92		$	1.00
Discontinued operations		(0.01	)		0.01
Total	$	0.91		$	1.01
Weighted-average shares, including effect of dilutive securities		329			330
Diluted earnings (loss) per common share:
Continuing operations	$	0.92		$	0.99
Discontinued operations		(0.01	)		0.01
Total	$	0.91		$	1.00
Dividends declared per common share	$	0.305		$	0.29


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


AB		Assembly Bill
AFUDC		allowance for funds used during construction
APS		Arizona Public Service Company
ARO(s)		asset retirement obligation(s)
Btu		British thermal units
CAA		Clean Air Act
CARB		California Air Resources Board
Commonwealth Edison		Commonwealth Edison Company
CDWR		California Department of Water Resources
CEC		California Energy Commission
CONE		cost of new entry
CPSD		Consumer Protection and Safety Division
CPUC		California Public Utilities Commission
CRRs		congestion revenue rights
D.C. District Court		U.S. District Court for the District of Columbia
DOE		United States Department of Energy
DOJ		Department of Justice
DPV2		Devers-Palo Verde II
DWP		Los Angeles Department of Water & Power
EITF		Emerging Issues Task Force
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
FGIC		Financial Guarantee Insurance Company
FIN 39-1		Financial Accounting Standards Board Interpretation No. 39-1, Amendment of FASB Interpretation No. 39
FIN 48		Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FAS 109
FTRs		firm transmission rights
GAAP		general accepted accounting principles
GHG		greenhouse gas
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
Midway-Sunset		Midway-Sunset Cogeneration Company


	Three Months Ended March 31,
In millions	2008			2007
	(Unaudited)
Net income	$	299		$	333
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments – net		(3	)		(2	)
Pension and postretirement benefits other than pensions:
Amortization of net gain (loss) included in expense – net		—			1
Unrealized gains (losses) on cash flow hedges:
Other unrealized losses arising during the period – net of income tax benefit of $(92) and $(115) for 2008 and 2007, respectively		(138	)		(169	)
Reclassification adjustment for gain (loss) included in net income – net of income tax expense (benefit) of $(6) and $12 for 2008 and 2007, respectively		(9	)		16
Other comprehensive loss		(150	)		(154	)
Comprehensive income	$	149		$	179


In millions	March 31, 2008			December 31, 2007
		(Unaudited	)
ASSETS
Cash and equivalents	$	1,545		$	1,441
Short-term investments		35			81
Receivables, less allowance of $34 for uncollectible accounts at each date		1,038			1,033
Accrued unbilled revenue		342			370
Fuel inventory		120			116
Materials and supplies		311			316
Derivative assets		192			109
Restricted cash		3			3
Margin and collateral deposits		147			121
Regulatory assets		128			197
Accumulated deferred income taxes – net		218			167
Other current assets		339			290
Total current assets		4,418			4,244
Nonutility property – less accumulated provision for depreciation of $1,822 and $1,765 at respective dates		4,951			4,906
Nuclear decommissioning trusts		3,195			3,378
Investments in partnerships and unconsolidated subsidiaries		260			272
Investments in leveraged leases		2,486			2,473
Other investments		108			96
Total investments and other assets		11,000			11,125
Utility plant, at original cost:
Transmission and distribution		19,158			18,940
Generation		1,795			1,767
Accumulated provision for depreciation		(5,306	)		(5,174	)
Construction work in progress		1,820			1,693
Nuclear fuel, at amortized cost		231			177
Total utility plant		17,698			17,403
Derivative assets		135			122
Restricted cash		45			48
Rent payments in excess of levelized rent expense under plant operating leases		765			716
Regulatory assets		2,726			2,721
Other long-term assets		1,164			1,144
Total long-term assets		4,835			4,751

Total assets	$	37,951		$	37,523


In millions, except share amounts	March 31, 2008			December 31, 2007
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Short-term debt	$	400		$	500
Long-term debt due within one year		164			18
Accounts payable		807			979
Accrued taxes		119			49
Accrued interest		223			160
Counterparty collateral		48			42
Customer deposits		221			219
Book overdrafts		192			212
Derivative liabilities		203			125
Regulatory liabilities		1,201			1,019
Other current liabilities		814			933
Total current liabilities		4,392			4,256
Long-term debt		9,325			9,016
Accumulated deferred income taxes – net		5,201			5,196
Accumulated deferred investment tax credits		112			114
Customer advances		149			155
Derivative liabilities		111			101
Power-purchase contracts		22			22
Accumulated provision for pensions and benefits		1,133			1,089
Asset retirement obligations		2,925			2,892
Regulatory liabilities		3,256			3,433
Other deferred credits and other long-term liabilities		1,654			1,595
Total deferred credits and other liabilities		14,563			14,597
Total liabilities		28,280			27,869
Commitments and contingencies (Note 5)
Minority interest		282			295
Preferred and preference stock of utility not subject to mandatory redemption		907			915
Common stock, no par value (325,811,206 shares outstanding at each date)		2,238			2,225
Accumulated other comprehensive loss		(242	)		(92	)
Retained earnings		6,486			6,311
Total common shareholders’ equity		8,482			8,444

Total liabilities and shareholders’ equity	$	37,951		$	37,523


	Three Months Ended March 31,
In millions	2008			2007
	(Unaudited)
Cash flows from operating activities:
Net income	$	299		$	333
Less: Income (loss) from discontinued operations		(5	)		3
Income from continuing operations		304			330
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization		298			313
Realized loss on impairment of nuclear decommissioning trusts		45			8
Other amortization		27			31
Gain on buyout of contract and sale of assets		(17	)		—
Stock based compensation		6			6
Minority interest		8			19
Deferred income taxes and investment tax credits		31			(158	)
Equity in income from partnerships and unconsolidated subsidiaries		(2	)		(16	)
Income from leveraged leases		(13	)		(16	)
Regulatory assets		77			173
Regulatory liabilities		186			152
Levelized rent expense		(48	)		(49	)
Derivative assets		(96	)		(105	)
Derivative liabilities		(162	)		(201	)
Other assets		(20	)		(14	)
Other liabilities		92			226
Margin and collateral deposits – net of collateral received		(21	)		(7	)
Receivables and accrued unbilled revenue		22			77
Inventory and other current assets		(35	)		(90	)
Book overdraft		(20	)		24
Accrued interest and taxes		133			266
Accounts payable and other current liabilities		(215	)		(238	)
Distributions and dividends from unconsolidated entities		(2	)		(1	)
Operating cash flows from discontinued operations		(5	)		3
Net cash provided by operating activities		573			733
Cash flows from financing activities:
Long-term debt issued		677			30
Long-term debt issuance costs		(9	)		(1	)
Long-term debt repaid		(7	)		(95	)
Bonds repurchased		(212	)		—
Preference stock redeemed		(7	)		—
Rate reduction notes repaid		—			(62	)
Short-term debt financing – net		(100	)		120
Shares purchased for stock-based compensation		(24	)		(106	)
Proceeds from stock option exercises		7			39
Excess tax benefits related to stock option exercises		6			17
Dividends to minority shareholders		(17	)		(24	)
Dividends paid		(99	)		(94	)
Net cash provided (used) by financing activities	$	215		$	(176	)


	Three Months Ended March 31,
In millions	2008			2007
	(Unaudited)
Basic earnings per share - continuing operations:
Income from continuing operations	$	304		$	330
Gain on redemption of preferred stock		2			—
Participating securities dividends		(5	)		(5	)
Income from continuing operations available to common shareholders	$	301		$	325
Weighted average common shares outstanding		326			326
Basic earnings per share - continuing operations	$	0.92		$	1.00

Diluted earnings per share - continuing operations:
Income from continuing operations available to common shareholders	$	301		$	325
Income impact of assumed conversions		2			3
Income from continuing operations available to common shareholders and assumed conversions	$	303		$	328
Weighted average common shares outstanding		326			326
Incremental shares from assumed conversions		3			4
Adjusted weighted average shares - diluted		329			330
Diluted earnings per share - continuing operations	$	0.92		$	0.99


In millions	March 31, 2008		December 31, 2007
	(Unaudited	)
Commercial paper	$ 3		$ 32
Certificates of deposit	30		41
Treasury bills	2		7
Corporate bonds	—		1
Total	$ 35		$ 81


In millions	(Unaudited)
Balance at January 1, 2008	$	2,114
Tax positions taken during the current year
Increases		78
Decreases		—
Tax positions taken during a prior year
Increases		20
Decreases		(63	)
Decreases for settlements during the period		—
Reductions for lapses of applicable statute of limitations		—
Balance at March 31, 2008	$	2,149


In millions	Tax Years Under Appeal 1994 – 1999		Tax Years Under Audit 2000 – 2002		Unaudited Tax Years 2003 – 2007			Total
Replacement Leases (SILO)	$	44	$	19	$	27		$	90
Lease/Leaseback (LILO)		563		566		(8	)		1,121
Service Contract (SILO)		—		127		253			380
Total	$	607	$	712	$	272		$	1,591


			Weighted-Average
	Stock Options		Exercise Price		Remaining Contractual Term (Years)	Aggregate Intrinsic Value
	(Unaudited)
Outstanding at December 31, 2007	12,105,642		$	30.55
Granted	2,269,209		$	49.95
Expired	(500	)	$	28.94
Forfeited	(19,292	)	$	47.36
Exercised	(250,740	)	$	26.30
Outstanding at March 31, 2008	14,104,319		$	33.73	6.75
Vested and expected to vest at March 31, 2008	13,615,947		$	33.28	6.68	$	240,559,743
Exercisable at March 31, 2008	8,792,954		$	26.44	5.58	$	215,493,320


In millions	Unrealized Gain (Loss) on Cash Flow Hedges			Foreign Currency Translation Adjustment			Pension and PBOP– Net Loss			Pension and PBOP– Prior Service Cost		Accumulated Other Comprehensive Income (Loss)
		(Unaudited)
Balance at December 31, 2007	$	(60	)	$	(1	)	$	(34	)	$	3	$	(92	)
Current period change		(147	)		(3	)		—			—		(150	)
Balance at March 31, 2008	$	(207	)	$	(4	)	$	(34	)	$	3	$	(242	)


In millions	Level 1			Level 2			Level 3			Netting and Collateral⁽¹⁾			Total at March 31, 2008
	(Unaudited)
Assets at Fair Value
Derivative contracts	$	—		$	101		$	249		$	(10	)	$	340
Nuclear decommissioning trusts⁽²⁾		2,182			961			—			—			3,143
Long-term disability plan		—			6			—			—			6
Total assets⁽³⁾		2,182			1,068			249			(10	)		3,489
Liabilities at Fair Value
Derivative contracts		(91	)		(309	)		(58	)		134			(324	)
Net assets	$	2,091		$	759		$	191		$	124		$	3,165


In millions	(Unaudited)
Fair value of derivative contracts, net at January 1, 2008	$	98
Total realized/unrealized gains (losses):
Included in earnings⁽¹⁾		86
Included in accumulated other comprehensive loss		(2	)
Purchases and settlements, net		12
Transfers in and/or out of Level 3		(3	)
Fair value of derivative contracts, net at March 31, 2008	$	191
Change during the period in unrealized gains (losses) related to net derivative contracts, held at March 31, 2008⁽²⁾	$	65


In millions	Maturity Dates	March 31, 2008		December 31, 2007
		(Unaudited)
Municipal bonds	2008 – 2044	$	578	$	561
Stocks	–		1,910		1,968
United States government issues	2008 – 2049		651		552
Corporate bonds	2008 – 2047		41		241
Short-term	2008		15		56
Total		$	3,195	$	3,378


In millions	March 31 2008		December 31, 2007
	(Unaudited)
Current:
Regulatory balancing accounts	$	1,017	$	967
Rate reduction notes – transition cost overcollection		20		20
Energy derivatives		97		10
Deferred FTR costs		62		19
Other		5		3
		1,201		1,019
Long-term:
Regulatory balancing accounts		2		—
Asset retirement obligations		582		793
Costs of removal		2,248		2,230
SFAS No. 158 pensions and other postretirement benefits		311		308
Energy derivatives		38		27
Employee benefit plans		75		75
		3,256		3,433
Total Regulatory Liabilities	$	4,457	$	4,452


		PAGE
Current Developments		38
Southern California Edison Company		40
Edison Mission Group		48
Edison International (Parent)		64
Results of Operations and Historical Cash Flow Analysis		66
New Accounting Pronouncements		75
Commitments, Guarantees and Indemnities		76
Other Developments		77


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


In millions		March 31, 2008
S&P Credit Rating
A or higher		$ 59
A-		6
BBB+		15
BBB		—
BBB-		—
Below investment grade and not rated		270
Total		$ 350


Date	SCE System Average Rate	Portion Related to CDWR
January 1, 2007	14.5¢ per-kWh	3.1¢ per-kWh
February 14, 2007	13.9¢ per-kWh	3.0¢ per-kWh
January 1, 2008	13.8¢ per-kWh	2.9¢ per-kWh
March 1, 2008	13.9¢ per-kWh	2.9¢ per-kWh
April 7, 2008	13.8¢ per-kWh	2.9¢ per-kWh


	March 31, 2008			December 31, 2007
In millions	Assets		Liabilities	Assets	Liabilities
Energy options	$ 6		$ 45	$ 6	$ 49
FTRs	25		—	22	—
Forward physicals (power) and tolling arrangements	34		5	7	8
Gas options, swaps and forward arrangements	147		—	46	22
Netting and collateral	(4	)	—	—	(2	)
Total	$ 208		$ 50	$ 81	$ 77


In millions	April through December 2008		2009		2010
Illinois Plants
Plant capital expenditures	$	56	$	73	$	44
Environmental expenditures		53		58		246

Homer City Facilities
Plant capital expenditures		25		34		26
Environmental expenditures		12		9		8

New Projects
Projects under construction		142		4		—
Turbine commitments		484		651		117

Other capital expenditures		45		14		8
Total	$	817	$	843	$	449


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

EME Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	3.79 to 1


	24-Hour Northern Illinois Hub Historical Energy Prices⁽¹⁾
	2008		2007
January	$	47.09	$	35.75
February		54.46		56.64
March		58.58		42.04
Quarterly Average	$	53.38	$	44.81


	24-Hour Northern Illinois Hub Forward Energy Prices⁽¹⁾
2008
April	$	55.70
May		49.49
June		55.06
July		65.11
August		63.23
September		50.13
October		47.39
November		45.89
December		51.86
2009 Calendar “strip”⁽²⁾	$	55.48


	Historical Energy Prices⁽¹⁾ 24-Hour PJM
	Homer City Busbar				PJM West Hub
	2008		2007		2008		2007
January	$	54.32	$	40.30	$	66.80	$	44.63
February		61.74		64.27		68.29		73.93
March		65.37		55.00		70.48		61.02
Quarterly Average	$	60.48	$	53.19	$	68.52	$	59.86


	24-Hour Northern PJM West Hub Forward Energy Prices⁽¹⁾
2008
April	$	72.25
May		70.35
June		77.56
July		94.04
August		96.78
September		74.43
October		72.40
November		67.70
December		75.35
2009 Calendar “strip”⁽²⁾	$	75.55


	Fixed Price Capacity Sales
	Through RPM Auction, Net			Non-unit Specific Capacity Sales		Variable Capacity Sales
	MW	Price per MW-day		MW	Price per MW-day	MW	Price per MW-day
April 1, 2008 to May 31, 2008
Midwest Generation	2,629	$ 37.27		500	$ 21.31	—	—
EME Homer City	786	40.80		—	—	925	$ 70.37	⁽¹⁾
June 1, 2008 to May 31, 2009
Midwest Generation	2,978	123.77	⁽³⁾	880	64.35	—	—
EME Homer City	820	113.22	⁽³⁾	—	—	905	63.96	⁽²⁾
June 1, 2009 to May 31, 2010
Midwest Generation	4,614	102.04		715	71.46	—	—
EME Homer City	1,670	191.32		—	—	—	—
June 1, 2010 to May 31, 2011
Midwest Generation	4,929	174.29		—	—	—	—
EME Homer City	1,813	174.29		—	—	—	—


	Amount of Coal Under Contract in Millions of Tons⁽¹⁾
	April through December 2008	2009	2010	2011
Illinois plants	12.3	11.7	11.7	—
Homer City facilities	4.3	4.4	0.4	0.1


In millions	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	(388	)	$	(271	)	$	(117	)	$	—	$	—


In millions
Fair value of trading contracts at January 1, 2008	$	132
Net gains from energy trading activities		42
Amount realized from energy trading activities		(51	)
Other changes in fair value		(7	)
Fair value of trading contracts at March 31, 2008	$	116


In millions	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	(1	)	$	(19	)	$	18	$	—	$	—
Prices based on models and other valuation methods		117			45			14		23		35
Total	$	116		$	26		$	32	$	23	$	35