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:

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary for a fair statement of the financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States for the periods covered by this quarterly report on Form 10-Q. The results of operations for the period ended March 31, 2006 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 on Form 10-K for the year ended December 31, 2005 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 2005 Annual Report. Edison International follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for stock-based compensation (discussed below in “New Accounting Pronouncements”).

Certain prior-period amounts were reclassified to conform to the March 31, 2006 financial statement presentation. Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.

Edison International computes EPS using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International’s participating securities are vested stock options that earn dividend equivalents on an equal basis with common shares. Basic EPS is computed by dividing net income available for common stock by the weighted-average number of common shares outstanding. Net income available for common stock was $255 million and $200 million for the three months ended March 31, 2006, and 2005, respectively. In arriving at net income, dividends on preferred and preference stock have been deducted.

For the diluted EPS calculation, dilutive securities (stock-based compensation awards exercisable) are added to the weighted-average shares. Dilutive securities are excluded from the diluted EPS calculation for items with a net loss due to their antidilutive effect.

Edison International’s effective tax rate from continuing operations was 38% for the three-month period ended March 31, 2006 as compared to 35% for the same period in 2005. The increased effective tax rate resulted from reductions made to accrued tax liabilities at Southern California Edison Company (SCE) in 2005 exceeding reductions made to accrued tax liabilities in 2006. The reductions in both periods were made to reflect progress made in settlement negotiations relating to prior-year tax liabilities. This increase was partially offset by a reduction in nondeductible compensation paid by Edison International between the periods.

A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. Edison International implemented the new standard in the first quarter of 2006 and applied the modified prospective transition method. Under the modified prospective method, the new accounting standard was applied effective January 1, 2006 to the unvested portion of awards previously granted and will be applied to all prospective awards. Prior financial statements were not restated under this method. The new accounting standard resulted in the recognition of expense for all stock-based compensation awards. Prior to January 1, 2006, Edison International used the intrinsic value method of accounting, which resulted in no recognition of expense for its stock options.

Prior to adoption of the new accounting standard, Edison International presented all tax benefits of deductions resulting from the exercise of stock options as a component of operating cash flows under the caption “Other liabilities” in the consolidated statements of cash flows. The new accounting standard requires the cash flows resulting from the tax benefits that occur from estimated tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. The $9 million excess tax benefit is classified as a financing cash inflow in 2006.

Due to the adoption of this new accounting standard, Edison International recorded a cumulative effect adjustment that increased net income by approximately $1 million, net of tax, for the three months ended March 31, 2006, mainly to reflect the change in the valuation method for performance shares classified as liability awards and the use of forfeiture estimates.

In April 2006, the Financial Accounting Standards Board (FASB) issued a Staff Position that specifies how a company should determine the variability to be considered in applying the accounting standard for consolidation of variable interest entities. The pronouncement states that such variability shall be determined based on an analysis of the design of the entity, including the nature of the risks in the entity, the purpose for which the entity was created, and the variability the entity is designed to create and pass along to its interest holders. This new accounting guidance is effective prospectively beginning July 1, 2006, although companies may elect early application and/or retrospective application. Edison International is currently evaluating the impact of this new accounting pronouncement.

Edison International revised its consolidated statements of cash flows for the three months ended March 31, 2005 to separately disclose the operating, financing and investing portions of the cash flows attributable to discontinued operations consistent with its consolidated statements of cash flow for the year ended December 31, 2005 included in Edison International’s Annual report on Form 10-K for the year ended December 31, 2005. Edison International had previously reported these amounts on a combined basis in its quarterly report on Form 10-Q for the quarter ended March 31, 2005.

Edison International’s stock-based compensation plans primarily included the issuance of stock options and performance shares. Edison International usually does not issue new common stock for equity awards earned. Rather, a third party is used to facilitate the exercise of stock options and the purchase and delivery of outstanding common stock for settlement of performance shares earned. The amount of cash used to settle stock options exercised was $44 million and $31 million for the quarters ended March 31, 2006 and 2005, respectively. The amount of cash used to settle performance shares classified as equity awards was $37 million and $20 million for the quarters ended March 31, 2006 and 2005, respectively. Edison International has approximately 13.8 million shares remaining for future issuance under its stock-based compensation plans, which are described more fully in Note 2.

Prior to January 1, 2006, Edison International accounted for these plans using the intrinsic value method. Upon grant, no stock-based compensation cost for stock options was reflected in net income, as the grant date was the measurement date, and all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Previously, stock-based compensation cost for performance shares was remeasured at each reporting period and related compensation expense was adjusted. As discussed in “New Accounting Pronouncements” above, effective January 1, 2006, Edison International implemented a new accounting standard that requires companies to use the fair value accounting method for stock-based compensation resulting in the recognition of expense for all stock-based compensation awards. Edison International recognizes stock-based compensation expense on a straight-line basis over the vesting period. Edison International recognizes stock-based compensation expense for awards granted to retirement-eligible participants as follows: for stock-based awards granted prior to January 1, 2006, Edison International recognized stock-based compensation expense over the explicit vesting period and accelerated any remaining unrecognized compensation expense when a participant actually retired; for awards granted or modified after January 1, 2006 to participants who are retirement-eligible or will become retirement-eligible prior to the end of the normal vesting period for the award, stock-based compensation will be recognized on a prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes eligible for retirement. If Edison International recognized stock-based compensation expense for awards granted prior to January 1, 2006, over a period to the date the participant first became eligible for retirement, stock-based compensation expense would have decreased by $1 million for the quarter ended March 31, 2006 and would have increased less than $1 million for the quarter ended March 31, 2005.

Total stock-based compensation expense (reflected in the caption “Other operation and maintenance” on the consolidated statements of income) was $11 million and $20 million for the three months ended March 31, 2006 and 2005, respectively. The income tax benefit recognized in the income statement was $4 million and $8 million for the three months ended March 31, 2006 and 2005, respectively.

The following table illustrates the effect on net income and EPS if Edison International had used the fair-value accounting method for the quarter ended March 31, 2005.

Supplemental information regarding Edison International’s accumulated other comprehensive loss is:

The minimum pension liability is discussed in Note 6, Compensation and Benefit Plans of “Notes to Consolidated Financial Statements” included in Edison International’s 2005 Annual Report.

Included in Edison International’s accumulated other comprehensive loss at March 31, 2006, was a $55 million loss related to Edison Mission Energy’s (EME) net unrealized loss on cash flow hedges and a $4 million loss related to SCE’s interest rate swap (see discussion below).

Unrealized loss on cash flow hedges at March 31, 2006, includes an unrealized loss on commodity hedges primarily related to EME’s Homer City and Midwest Generation futures and forward electricity contracts that qualify for hedge accounting. This loss arise because current forecasts of future electricity prices in the relevant markets are greater than contract prices. The decrease in the unrealized loss during the first quarter of 2006 resulted from a decrease in market prices for power driven largely by lower natural gas prices.

Unrealized loss on cash flow hedges also included those related to SCE’s interest rate swap (the swap terminated on January 5, 2001, but the related debt was redeemed in April 2006 (see Note 10, “Subsequent Events”)). The

unamortized loss of $4 million (as of March 31, 2006, net of tax) on the interest rate swap will no longer be reflected in accumulated other comprehensive income.

As EME’s hedged positions for continuing operations are realized, approximately $54 million (after tax) of the net unrealized loss on cash flow hedges at March 31, 2006 is expected to be reclassified into earnings during the next 12 months. EME expects that reclassification of the net unrealized loss will offset energy revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which an EME cash flow hedge is designated is through December 31, 2007.

Edison International previously disclosed in Note 6 of “Notes to Consolidated Financial Statements” included in Edison International’s 2005 Annual Report that it expects to contribute approximately $66 million to its pension plans in 2006. As of March 31, 2006, $35 million in contributions have been made. Edison International anticipates that its original expectations will be met by year-end 2006.

Edison International previously disclosed in Note 6 of “Notes to Consolidated Financial Statements” included in Edison International’s 2005 Annual Report that it expects to contribute approximately $79 million to its postretirement benefits other than pensions plans in 2006. As of March 31, 2006, $6 million in contributions have been made. Edison International anticipates that its original expectation will be met by year-end 2006.

Under various plans, Edison International may grant stock options at exercise prices equal to the average of the high and low price at the grant date and other awards related to or with a value derived from its common stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of four years of continuous service, with expense recognized evenly over the vesting period, except for awards granted to retirement-eligible participants, as discussed in “Stock-Based Compensation” in Note 1. Stock-based compensation expense associated with stock options was $8 million for the three months ended March 31, 2006. Under prior accounting rules, there was no comparable expense recognized for the same period in 2005. See “Stock-Based Compensation” in Note 1 for further discussion.

Beginning with awards made in 2003, stock options accrue dividend equivalents for the first five years of the option term. Unless transferred to non-qualified deferral plan accounts, dividend equivalents accumulate without

interest. Dividend equivalents are paid only on options that vest, including options that are unexercised. Dividend equivalents are paid in cash after the vesting date. Edison International has discretion to pay certain dividend equivalents in shares of Edison International common stock. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.

The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in the following table.

The expected term of options granted is based on the actual remaining contractual term of the options. The risk-free interest rate for periods within the contractual life of the option is based on a 52-week historical average of the 10-year semi-annual coupon U.S. Treasury note. In 2006, expected volatility is based on the historical volatility of Edison International’s common stock for the recent 36 months. Prior to January 1, 2006, expected volatility was based on the median of the most recent 36 months historical volatility of peer companies because Edison International’s historical volatility was impacted by the California energy crisis.

The weighted-average grant-date fair value of options granted during the quarters ended March 31, 2006 and 2005, was $14.47 and $11.68, respectively. The total intrinsic value of options exercised during the quarters ended March 31, 2006 and 2005, was $24 million and $12 million, respectively. At March 31, 2006, there was $64 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately 2 years.

Cash received from options exercised for the quarters ended March 31, 2006 and 2005, was $21 million and $20 million, respectively. The estimated tax benefit from options exercised was $9 million and $4 million for the quarters ended March 31, 2006 and 2005, respectively.

A target number of contingent performance shares were awarded to executives in January 2004, January 2005 and March 2006, and vest at the end of December 2006, 2007 and 2008, respectively. Dividend equivalents associated with these performance shares accumulate without interest and will be payable in cash following the end of the performance period when the performance shares are paid, although Edison International has discretion to pay certain dividend equivalents in Edison International common stock. The vesting of Edison International’s performance shares is dependent upon a market condition and three years of continuous service subject to a prorated adjustment for employees who are terminated under certain circumstances or retire, but payment cannot be accelerated. The market condition is based on Edison International’s common stock performance relative to the performance of a specified group of companies at the end of a three-calendar-year period. The number of performance shares earned is determined based on Edison International’s ranking among these companies. Dividend equivalents will be adjusted to correlate to the actual number of performance shares paid. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Additionally, cash awards are substituted to the extent necessary to pay tax withholding or any government levies. The portion of performance shares settled in cash is classified as a share-based liability award. The fair value of these shares is remeasured at each reporting period and the related compensation expense is adjusted. The portion of performance shares payable in common stock is classified as a share-based equity award. Compensation expense related to these shares is based on the grant-date fair value. Performance shares expense is recognized ratably over the vesting period based on the fair values determined, except for awards granted to retirement-eligible participants, as discussed in “Stock-Based Compensation” in Note 1. Stock-based compensation expense associated with performance shares was $3 million and $13 million for the three months ended March 31, 2006 and 2005, respectively.

The performance shares’ fair value is determined using a Monte Carlo simulation valuation model. The Monte Carlo simulation valuation model requires various assumptions. Assumptions specifically related to Edison International are noted in the following table.

The risk-free interest rate is based on a 52-week historical average of the three-year semi-annual coupon U.S. Treasury note and is used as proxy for the expected return for the specified group of companies. Volatility is based on the historical volatility of Edison International’s common stock for the recent 36 months. Historical volatility for each company in the specified group is obtained from data published by Bloomberg.

The total intrinsic value of performance shares settled during the quarters ended March 31, 2006 and 2005, was $72 million and $40 million, respectively, which included cash paid to settle the performance shares classified as liability awards of $24 million and $13 million for the three months ended March 31, 2006 and 2005, respectively. At March 31, 2006, there was $18 million (based on the March 31, 2006 fair value of performance

shares classified as liability awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately 2 years.

A summary of the status of Edison International nonvested performance shares classified as equity awards is as follows:

The weighted-average grant-date fair value of performance shares classified as equity awards granted during the quarter ended March 31, 2005, was $46.09.

A summary of the status of Edison International nonvested performance shares classified as liability awards (the current portion is reflected in the caption “Other current liabilities” and the long-term portion is reflected in “Accumulated provision for pensions and benefits” on the consolidated balance sheets) is as follows:

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

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

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

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

Edison International’s recorded estimated minimum liability to remediate its 35 identified sites at SCE (24 sites) and EME (11 sites related to Midwest Generation) is $83 million, $81 million of which is related to SCE. Edison International’s other subsidiaries have no identified remediation sites. The ultimate costs to clean up Edison International’s identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $114 million, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 31 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to $9 million.

The California Public Utilities Commission (CPUC) allows SCE to recover environmental remediation costs at certain sites, representing $29 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $55 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 $25 million. Recorded costs for the twelve months ended March 31, 2006 were $13 million.

Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC’s regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

Edison International received Revenue Agent Reports from the Internal Revenue Service (IRS) in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994–1996 and 1997–1999 tax years, respectively. Many of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of penalties), if any, would be deductible on future tax returns of Edison International.

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

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

Edison Capital also entered into a lease/service contract transaction in 1999 involving a foreign telecommunication system (Service Contract, which the IRS also refers to as a SILO). The IRS did not yet assert an adjustment for the Service Contract but is expected to challenge the Service Contract in subsequent audit cycles.

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

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

If Edison International is not successful in its defense of the tax treatment for these lease transactions, the payment of taxes, exclusive of any interest or penalties, would not affect results of operations under current accounting standards; however, the imposition of interest and any penalties at 20% of any tax adjustment sustained by the IRS would have a material impact on earnings. As of March 31, 2006, the interest on the proposed tax adjustments (excluding penalties) is estimated to be $346 million. Moreover, the FASB is currently considering changes to the accounting for leveraged leases which, if adopted, will be applicable to those leases where the tax treatment or the timing of the realization of tax benefits associated with them is altered. Under the proposed accounting rule, a change in the timing of expected cash flows related to these lease, including the realization of the tax benefits, would require the recalculation of the income allocated over the life of the lease, with the cumulative effect of the change recognized immediately. This could result in a material charge against earnings, although future income would be expected to increase over the remaining terms of the affected leases.

In addition, the payment of taxes, interest and penalties could have a significant impact on cash flow. In connection with litigation of this matter, Edison International may pay a portion of the taxes plus interest and penalties and then seek a refund that accrues interest to the extent it prevails. Such payment may be made in 2006. The source of funds for such payment would likely be cash and cash equivalents on hand at Edison Capital or funds borrowed at Edison Capital. At this time, Edison International is unable to predict the impact of the ultimate resolution of these matters.

The IRS Revenue Agent Report for the 1997–1999 audit also asserted deficiencies with respect to a transaction entered into by an SCE subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability company. While Edison International intends to defend its tax return position with respect to this transaction, the tax benefits relating to the capital loss deductions will not be claimed for financial accounting and reporting purposes until and unless these tax losses are sustained.

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

In 2000, the FERC initiated an investigation into the justness and reasonableness of rates charged by sellers of electricity in the California Power Exchange (PX) and California Independent System Operations (ISO) markets. On March 26, 2003, the FERC staff issued a report concluding that there had been pervasive gaming and market manipulation of both the electric and natural gas markets in California and on the West Coast during 2000–2001 and describing many of the techniques and effects of that market manipulation. SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets. SCE is required to refund to customers 90% of any refunds actually realized by SCE net of litigation costs, except for the El Paso Natural Gas Company settlement agreement (see discussion in Note 9 of “Notes to Consolidated Financial Statements” in Edison International’s 2005 Annual Report), and 10% will be retained by SCE as a shareholder incentive. A brief summary of the various settlements is below:

On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an energy settlement memorandum account (ESMA) for the purpose of recording the foregoing settlement proceeds from energy providers and allocating them in accordance with a settlement agreement. The resolution provides a mechanism whereby portions of the settlement proceeds recorded in the ESMA are allocated to recovery of SCE’s litigation costs and expenses in the FERC refund proceedings described above and the 10% shareholder incentive. Remaining amounts for each settlement are to be refunded to ratepayers through the energy resource recovery account mechanism. During 2005, SCE recognized $23 million in shareholder incentives related to the FERC refunds described above.

SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to earn rewards or penalties based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability.

SCE has been conducting investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings of misconduct and misreporting as further discussed below. As a result of the reported events, the CPUC could institute its own proceedings to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer satisfaction, injury and illness reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose additional penalties on SCE. SCE cannot predict the outcome of these matters or estimate the potential amount of refunds, disallowances, and penalties that may be required.

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 to SCE under the PBR provisions for customer satisfaction. SCE recorded aggregate customer satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of approximately $10 million for 2003.

Following its internal investigation, SCE proposed to refund to ratepayers $7 million of the PBR rewards previously received and forgo an additional $5 million of the PBR rewards pending that are both attributable to the design organization’s portion of the customer satisfaction rewards for the entire PBR period (1997–2003). In addition, SCE also proposed to refund all of the approximately $2 million of customer satisfaction rewards associated with meter reading. As a result of these findings, SCE accrued a $9 million charge in 2004 for the potential refunds of rewards that have been received.

SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of 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 general rate case.

The CPUC has not yet opened a formal investigation into this matter. However, it has submitted several data requests to SCE and has requested an opportunity to interview a number of SCE employees in the design

organization. SCE has responded to these requests and the CPUC has conducted interviews of approximately 20 employees who were disciplined for misconduct and four senior managers and executives of the transmission and distribution business unit.

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

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

As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the mechanism for any year before 2005, and it return to ratepayers the $20 million it has already received. Therefore, SCE accrued a $20 million charge in 2004 for the potential refund of these rewards. SCE has also proposed to withdraw the pending rewards for the 2001–2003 time frames.

SCE has taken other remedial action to address the issues identified, including revising its organizational structure and overall program for environmental, health and safety compliance and disciplining employees who committed wrongdoing. SCE submitted a report on the results of its investigation to the CPUC on December 3, 2004. As with the customer satisfaction matter, the CPUC has not yet opened a formal investigation into this matter.

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 schedule coordinators in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from schedule 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 PX, SCE’s schedule coordinator at the time, is estimated to be approximately $20 million to $25 million, including interest. On April 20, 2005, the FERC stayed its April 20, 2004 order during the pendency of SCE’s appeal filed with the Court of Appeals for the D.C. Circuit. On March 7, 2006, the Court of Appeals remanded the case back to the FERC at the FERC’s request and with SCE’s consent. A decision is expected in late 2006. The FERC may require SCE to pay these costs, but SCE does not believe this outcome is probable. If SCE is required to pay these costs, SCE may seek recovery in its reliability service rates.

Edison Capital has a net leveraged lease investment, before deferred taxes, of $58 million in three aircraft leased to American Airlines. American Airlines has reported net losses since 2000. 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, 2006, American Airlines was current in its lease payments to Edison Capital.

Edison Capital also has a net leveraged lease investment, before deferred taxes, of $44 million in a large natural gas-fired cogeneration plant leased to Midland Cogeneration Venture. During 2005, Midland Cogeneration Venture wrote down the book value of the power plant as a result of a substantial increase in long-term natural gas prices. A default of the lease could result in a loss of some or all of Edison Capital’s lease investment. At March 31, 2006, Midland Cogeneration Venture was current in its payments under the lease.

Midwest Independent Transmission System Operator (MISO) Revenue Sufficiency Guarantee Charges

On April 25, 2006, the FERC issued an order regarding the MISO’s “Revenue Sufficiency Guarantee” charges (RSG charges). The MISO’s business practice manuals and other instructions to market participants have stated, since the implementation of market operations in April 1, 2005, that RSG charges will not be imposed on offers to supply power not supported by actual generation (also known as virtual supply offers). However, some market participants raised questions about the language of the MISO’s tariff concerning that issue and in October 2005, the MISO submitted to the FERC proposed tariff revisions clarifying its tariff to reflect its business practices with respect to RSG charges, and filed corrected tariff sheets exempting virtual supply from RSG charges. In its April 25 decision, the FERC interpreted the MISO’s tariff to require that virtual supply offers must be included in the calculation of the RSG charges and that to the extent that the MISO did not charge virtual supply offers for RSG charges, it violated the terms of its tariff. The FERC order then proceeded to require the MISO to recalculate the RSG charges back to April 1, 2005, and to make refunds to customers, with interest, reflecting the recalculated charges. In order to make such refunds, it is likely that the MISO will attempt to impose retroactively RSG charges on those who submitted virtual supply offers during the recalculation period. Edison Mission Marketing & Trading (EMMT) made virtual supply offers in the MISO during this period on which no RSG charges were imposed, and thus may be subject to a claim for refunds from the MISO (which claim will be contested by EMMT). Because calculation of any claimed liability for refunds depends on information not currently available to it, EMMT cannot reasonably estimate a range of loss related to this matter. In addition, it is likely that the FERC’s April 25 order will be challenged by the MISO and other parties, including EMMT, and the eventual outcome of these proceedings is unclear. The FERC’s order also requires the MISO to modify its tariff on a prospective basis to impose RSG charges on virtual supply offers. At this time, it is not possible to predict how the prospective effect of the order will affect the nature and operation of the MISO markets.

In June 1999, the Navajo Nation filed a complaint in the United States District Court for the District of Columbia (D.C. District Court) against Peabody Holding Company (Peabody) and certain of its affiliates, Salt River Project Agricultural Improvement and Power District, and SCE arising out of the coal supply agreement for the Mohave Generating Station (Mohave). The complaint asserts claims for, among other things, violations of the federal Racketeer Influenced and Corrupt Organizations statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentation 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, as well as a declaration that Peabody’s lease and contract rights to mine coal on Navajo Nation lands should be terminated. SCE joined Peabody’s motion to strike the Navajo Nation’s complaint. In addition, SCE and other defendants filed motions to dismiss. The D.C. District Court denied these motions for dismissal, except for Salt River Project Agricultural Improvement and Power District’s motion for its separate dismissal from the lawsuit.

Certain issues related to this case were addressed by the United States Supreme Court in a separate legal proceeding filed by the Navajo Nation in the United States Court of Federal Claims against the United States Department of Interior. In that action, the Navajo Nation claimed that the Government breached its fiduciary duty concerning negotiations relating to the coal lease involved in the Navajo Nation’s lawsuit against SCE and Peabody. On March 4, 2003, the Supreme Court concluded, by majority decision, that there was no breach of a fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. Based on the Supreme Court’s conclusion, SCE and Peabody brought motions to dismiss or for summary judgment in the D.C. District Court action but the D.C. District Court denied the motions on April 13, 2004.

The Court of Appeals for the Federal Circuit, acting on a suggestion filed by the Navajo Nation on remand from the Supreme Court’s March 4, 2003 decision held, in an October 24, 2003 decision that the Supreme Court’s decision was focused on three specific statutes or regulations and therefore did not address the question of whether a network of other statutes, treaties and regulations imposed judicially enforceable fiduciary duties on the United States during the time period in question. On March 16, 2004, the Federal Circuit issued an order remanding the case against the Government to the Court of Federal Claims, which considered (1) whether the Navajo Nation previously waived its “network of other laws” argument and, (2) if not, whether the Navajo Nation can establish that the Government breached any fiduciary duties pursuant to such “network.” On December 20, 2005, the Court of Federal Claims issued its ruling and found that although there was no waiver, the Navajo Nation did not establish that a “network of other laws” created a judicially enforceable trust obligation. The Navajo Nation filed a notice of appeal from this ruling on February 14, 2006.

Pursuant to a joint request of the parties, the D.C. District Court granted a stay of the action in that court to allow the parties to attempt to resolve, through facilitated negotiations, all issues associated with Mohave. Negotiations are ongoing and the stay has been continued until further order of the court.

SCE cannot predict the outcome of the 1999 Navajo Nation’s complaint against SCE, the impact on the complaint of the Supreme Court’s decision and the recent Court of Federal Claims ruling in the Navajo Nation’s suit against the Government, or the impact of the complaint on the possibility of resumed operation of Mohave following the cessation of operation on December 31, 2005.

Federal law limits public liability claims from a nuclear incident to $10.8 billion. SCE and other owners of San Onofre Nuclear Generating Station (San Onofre) and Palo Verde Nuclear Generating Station (Palo Verde) have purchased the maximum private primary insurance available ($300 million). The balance is covered by the industry’s retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site. Federal regulations require this secondary level of financial protection. The Nuclear Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective June 1994. The current maximum deferred premium for each nuclear incident is $101 million per reactor, but not more than $15 million per reactor may be charged in any one year for each incident. The maximum deferred premium per reactor and the yearly assessment per reactor for each nuclear incident will be adjusted for inflation on a 5-year schedule. The next inflation adjustment will occur on August 31, 2008. Based on its ownership interests, SCE could be required to pay a maximum of $199 million per nuclear incident. However, it would have to pay no more than $30 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to $42 million per year. Insurance premiums are charged to operating expense.

California law requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2017. The Joint Energy Action Plan adopted in 2003 by the CPUC and the California Energy Commission (CEC) accelerated the deadline to 2010.

SCE entered into a contract with Calpine Energy Services, L.P. (Calpine) to purchase the output of certain existing geothermal facilities in northern California. On January 30, 2003, the CPUC issued a resolution approving the contract. SCE interpreted the resolution as authorizing SCE to count all of the output of the geothermal facilities towards the obligation to increase SCE’s procurement from renewable resources and counted the entire output of the facilities toward its 1% obligation in 2003, 2004 and 2005. On July 21, 2005, the CPUC issued a decision stating that SCE can only count procurement pursuant to the Calpine contract towards its 1% annual renewable procurement requirement if it is certified as “incremental” by the CEC. On February 1, 2006, the CEC certified approximately 25% and 17% of SCE’s 2003 and 2004 procurement, respectively, from the Calpine geothermal facilities as “incremental.” A similar outcome is anticipated with respect to the CEC’s certification review for 2005.

On August 26, 2005, SCE filed an application for rehearing and a petition for modification of the CPUC’s July 21, 2005 decision. On January 26, 2006, the CPUC denied SCE’s application for rehearing of the decision. The CPUC has not yet ruled on SCE’s petition for modification. The petition for modification seeks a clarification that SCE will not be subjected to penalties for relying on the CPUC’s 2003 resolution in submitting compliance reports to the CPUC and planning its subsequent renewable procurement activities. The petition for modification also seeks an express finding that the decision will be applied prospectively only; i.e., that no past procurement deficits will accrue for any prior period based on the decision.

If SCE is not successful in its attempt to modify the July 21, 2005 CPUC decision and can only count the output deemed “incremental” by the CEC, SCE could have deficits in meeting its renewable procurement obligations for 2003 and 2004. However, based on the CPUC’s rules for compliance with renewable procurement targets, SCE may have until 2007 to make up these deficits before becoming subject to penalties for those years. The CEC’s and the CPUC’s treatment of the output from the geothermal facilities could also result in SCE being deemed to be out of compliance in 2005 and 2006. Under current CPUC decisions, potential penalties for SCE’s failure to achieve its renewable procurement obligations for any year will be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance filing.

On December 20, 2005, Calpine and certain of its affiliates initiated Chapter 11 bankruptcy proceedings in the United States Bankruptcy Court for the Southern District of New York. As part of those proceedings, Calpine sought to reject its contract with SCE as of the petition filing date. On January 27, 2006, after the matter had been withdrawn from the Bankruptcy Court’s jurisdiction, the United States District Court for the Southern District of New York denied Calpine’s motion to reject the contract and ruled that the FERC has exclusive jurisdiction to

alter the terms of the contract with SCE. Calpine has appealed the District Court’s ruling to the United States Court of Appeals for the Second Circuit. Calpine may also file a petition with the FERC seeking authorization to reject the contract. The CPUC may take the position that any authorized rejection of the contract would cause SCE to be out of compliance with its renewable procurement obligations during any period in which renewable electricity deliveries are reduced or eliminated as a result of the rejection.

Further, in December 2005, SCE made filings advising the CPUC that the need for transmission upgrades to interconnect new renewable projects and the time it will take under the current process to license and construct such transmission upgrades may prevent SCE from meeting its statutory renewables procurement obligations through 2010 and potentially beyond 2010 depending in part on the results of a pending solicitation for new renewable resources. SCE has requested that the CPUC take several actions in order to expedite the licensing process for transmission upgrades. The CPUC may take the position that SCE’s failure to meet the 20% goal by 2010 due to transmission constraints would cause SCE to be out of compliance with its renewable procurement obligations.

Under the CPUC’s current rules, the maximum penalty for failing to achieve renewables procurement targets is $25 million per year. SCE cannot predict whether it will be assessed penalties.

SCE serves as a schedule coordinator for the Los Angeles Department of Water & Power (DWP) over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund for FERC-authorized charges incurred by SCE on the DWP’s behalf. The schedule coordinator charges are billed to the DWP under a FERC tariff that remains subject to dispute. The DWP has paid the amounts billed under protest but requested the FERC declare that SCE was obligated to serve as the DWP’s schedule 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 at the FERC. As a result, SCE could be required to refund all or part of the amounts collected from the DWP under the tariff. During the fourth quarter of 2005 SCE accrued a $25 million charge to earnings for the potential refunds. If the FERC ultimately rules that SCE may not collect the schedule coordinator charges from the DWP and requires the amounts collected to be refunded to the DWP, SCE would attempt to recover the schedule coordinator charges from all transmission grid customers through another regulatory mechanism. However, the availability of other recovery mechanisms is uncertain, and ultimate recovery of the schedule coordinator charges cannot be assured.

Under federal law, the United States Department of Energy (DOE) is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its obligation to begin acceptance of spent nuclear fuel not later than January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to 0.1¢-per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE’s failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. The case was stayed through April 7, 2006, when SCE and the DOE filed Joint Status Report in which SCE sought to lift the stay and the government opposed lifting the stay. On April 19, 2006, the Court ordered SCE and the DOE to file another Joint Status Report, by May 8, 2006, outlining the specific issues in the case

and discussing whether any cases currently pending before the Court of Claims or Federal Circuit Court of Appeals are expected to address issues in SCE’s cases. SCE will continue to pursue having the stay lifted as soon as possible.

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

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

The following is an update to Edison International’s commitments. See Note 8 of “Notes to Consolidated Financial Statements” included in Edison International’s 2005 Annual Report for a detailed discussion.

At March 31, 2006, EME’s subsidiaries had firm commitments to spend approximately $163 million during the remainder of 2006 and $35 million in 2007 on capital and construction expenditures. The majority of these expenditures relate to the construction of the Wildorado wind project (see further discussion related to the Wildorado project in Note 8, Acquisition and Disposition). Also included are expenditures for boiler head replacement, dust collection and mitigation system and various other projects. These expenditures are planned to be financed by existing subsidiary credit agreements, cash on hand or cash generated from operations.

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

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

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

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company 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 existing asbestos claims and expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement has a five-year term with an automatic renewal provision (subject to the right of either party to terminate). Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were approximately 176 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at March 31, 2006. Midwest Generation had recorded a $66 million liability at March 31, 2006 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.

Indemnity Provided as Part of EME’s Acquisition of the Homer City Facilities

In connection with the acquisition of the Homer City facilities, EME Homer City Generation L.P. (EME Homer City) agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale. 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. Payments would be triggered under this indemnity by a claim from the sellers. 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. EME also provided an indemnity to IPM for matters arising out of the exercise by one of its project partners of a purported right of first refusal. The right of first refusal matter has been submitted to arbitration, with hearings having been conducted during February 2006. It is expected that a decision of the arbitration panel will be rendered in the coming months. 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, 2006, EME had recorded a liability of $119 million related to these matters.

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

EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project’s power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. In addition, a subsidiary of EME has guaranteed the obligations of Sycamore Cogeneration Company under its project power sales agreement to repay capacity payments to the project’s power purchaser in the event that the project unilaterally terminates its performance or reduces its electric power producing capability during the term of the power sales agreements. The obligations under the indemnification agreements as of March 31, 2006, if payment were required, would be $116 million. EME has not recorded a liability related to these indemnities.

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific environmental claims related to SCE’s previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. The generating station has not operated since early 2001. SCE retained certain responsibilities with respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.

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

Edison International’s reportable business segments include its electric utility operation segment (SCE), a nonutility power generation segment (Mission Energy Holding Company (MEHC) – parent only and EME), and a financial services provider segment (Edison Capital).

Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment.

Short-term debt is used to finance fuel inventories, balancing account undercollections and general, temporary cash requirements. At March 31, 2006, Edison International’s outstanding short-term debt and weighted-average interest rate was $188 million and 4.79%, respectively.

Note 7. Preferred and Preference Stock of Utility Not Subject to Mandatory Redemption

In January 2006, SCE issued two million shares of 6.0% Series C preference stock (noncumulative, $100 liquidation value) and received net proceeds of $197 million. The Series C preference stock may not be redeemed prior to January 31, 2011. After January 31, 2011, SCE may, at its option, redeem the shares in whole or in part. The Series C preference stock has the same general characteristics as the Series A and B preference stock. See Note 4 of “Notes to Consolidated Financial Statements” included in Edison International’s 2005 Annual Report for additional information on SCE’s preference stock.

At March 31, 2006, accrued dividends related to SCE’s preferred and preference stock not subject to mandatory redemption were $10 million.

On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project, pursuant to a purchase agreement dated December 15, 2004, to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately $20 million. The sale of this investment had no significant effect on net income in the first quarter of 2005.

On January 10, 2005, EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) project to Corporacion IMPSA S.A., pursuant to a purchase agreement dated November 5, 2004. Proceeds from the sale were approximately $104 million. EME recorded a pre-tax gain on the sale of approximately $9 million during the first quarter of 2005.

EME previously owned a 220-MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by its counterparty, a subsidiary of TXU Europe Group plc and the project company was subsequently placed in liquidation. In response to its claim against the TXU subsidiary for damages from the termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the amount of the settlement remaining after payment of creditor claims. As creditor claims have been settled, EME has received to date payments of £13 million (approximately $24 million) in April 2005, £18 million (approximately $31 million) in February 2006, £43 million (approximately $75 million) in March 2006, and £9 million (approximately $16 million) in April 2006. For the first quarter of 2006, the after-tax income attributable to the Lakeland project was $73 million. Beginning in 2002, EME reported the Lakeland project among discontinued operations and accounts for its ownership of Lakeland Power on the cost method with earnings being recognized as cash is distributed from the project.

For both periods presented, the results of EME’s projects discussed above have been accounted for as discontinued operations in the consolidated financial statements in accordance with an accounting standard related to the impairment and disposal of long-lived assets.

There was no revenue for either of the quarters ended March 31, 2006 or 2005. For the three months ended March 31, 2006 and 2005, pre-tax income was $111 million and zero, respectively. For the three months ended March 31, 2005, there was a $9 million gain on sale before taxes.

There were no assets or liabilities of discontinued operations at March 31, 2006. At December 31, 2005, the assets and liabilities of discontinued operations were segregated on the consolidated balance sheet and were comprised of current assets of $2 million, other long-term assets of $9 million and long-term liabilities of $14 million.

On January 5, 2006, EME completed a transaction with Cielo Wildorado, G.P., LLC and Cielo Capital, L.P. to acquire a 99.9% interest in the Wildorado Wind Project, which owns a 161-MW wind farm located in the panhandle of northern Texas, referred to as the Wildorado wind project. The acquisition included all development rights, title and interest held by Cielo in the Wildorado wind project, except for a small minority stake in the project retained by Cielo. During the first quarter of 2006, construction started on the project with turbine deliveries scheduled to begin in November 2006 and commercial operations expected in April 2007.

The total purchase price was $29 million. As of March 31, 2006, a cash payment of $18 million was made towards the purchase price. Total project costs of the Wildorado wind project are estimated to be approximately $270 million. The acquisition was accounted for utilizing the purchase method. The fair value of the Wildorado wind project was equal to the purchase price and as a result the total purchase price was allocated to nonutility property in Edison International’s consolidated balance sheet.

On March 7, 2006, EME completed the sale of a 25% ownership interest in the San Juan Mesa wind project to Citi Renewable Investments I LLC, a wholly owned subsidiary of Citicorp North America, Inc. Proceeds from the sale were $43 million. EME recorded a pre-tax gain on the sale of approximately $4 million during the first quarter of 2006.

In April 2006, SCE issued $331 million of pollution-control bonds. The issuance included $196 million of 4.10% bonds due in April 2013 and $135 million of 4.25% bonds due in November 2016. The proceeds from the issuance of the bonds were used to call and redeem $135 million of pollution-control bonds due March 2008 and $196 million of pollution-control bonds due February 2008.

In April 2006, Edison Capital transferred its 196-MW portfolio of wind projects to EME. Edison Capital declared a dividend of the common stock of the companies owning this portfolio to Edison Mission Group, a subsidiary of Edison International and the holding company for MEHC and Edison Capital. Edison Mission Group contributed the shares to MEHC, who in turn contributed the shares to EME.

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

This Management’s Discussion and Analysis of Financial Condition and Results of Operation (MD&A) for the three-month period ended March 31, 2006 discusses material changes in the financial condition, results of operations and other developments of Edison International since December 31, 2005, and as compared to the three-month period ended March 31, 2005. This discussion presumes that the reader has read or has access to Edison International’s MD&A for the calendar year 2005 (the year-ended 2005 MD&A), which was included in Edison International’s 2005 annual report to shareholders and incorporated by reference into Edison International’s Annual Report on Form 10-K for the year ended December 31, 2005, 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 the “Risk Factors” section included in Part I, Item 1A of Edison International’s annual report on Form 10-K for the year ended 2005. 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 and 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, Edison Mission Energy (EME) and Edison Capital. Edison Mission Group Inc. (EMG), a subsidiary of Edison International is the holding company for its principal wholly owned subsidiaries, MEHC and Edison Capital. MEHC is the holding company for its wholly owned subsidiary EME. Beginning in 2006, MEHC and Edison Capital are presented on a consolidated basis as EMG. This change has been made to reflect the integration of management and personnel at MEHC and Edison Capital. In this MD&A, except when stated to the contrary, references to each of Edison International, SCE, EMG, MEHC, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to Edison International (parent) or parent company and MEHC (parent) mean Edison International or MEHC on a stand-alone basis, not consolidated with its subsidiaries.

This MD&A is presented in 9 major sections. The MD&A begins with a discussion of current developments. Following is a company-by-company discussion of SCE, EMG, and Edison International (parent) which 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, 2005. This section is not intended to be an all-inclusive list of all current developments related to each principal business segment. Further details of each current development discussed below can be found in the specific principal business segment’s section of this MD&A, along with discussions of liquidity, market risk exposures, and other matters as relevant to each principal business segment.

On December 21, 2004, SCE filed its application for a 2006 General Rate Case (GRC) and subsequently revised its requested 2006 base rate revenue requirement to $3.96 billion, an increase of $325 million over SCE’s 2005 base rate revenue requirement. SCE also proposed revised base rate revenue increases of $108 million for 2007 and $113 million for 2008.

On April 13, 2006, the CPUC assigned administrative law judge revised his January 17, 2006 proposed decision to correct several technical and substantive errors. On May 5, 2006, a third proposed decision was issued to increase authorized operating and maintenance expenses by an additional $45 million over the earlier revised proposed decision. The latest proposed decision would result in a 2006 base rate revenue requirement of $3.78 billion, an increase of $133 million over SCE’s 2005 base rate revenue requirement, and further increases of $74 million in 2007 and $104 million in 2008. A final CPUC decision is expected in the second quarter of 2006. See “SCE: Regulatory Matters—Current Regulatory Developments—2006 General Rate Case Proceeding.”

EME has undertaken a number of key activities in 2006 with respect to wind projects, including the following:

EME previously owned a 220-MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by its counterparty, a subsidiary of TXU Europe Group plc and the project company was subsequently placed in liquidation. In response to its claim for damages resulting from the termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the amount of the settlement remaining after payment of creditor claims. As creditor claims have been settled, EME has received payments of £61 million (approximately $106 million) during the first quarter of 2006. In addition, an additional distribution of £9 million (approximately $16 million) was received in April 2006. For the first quarter of 2006, the after-tax income attributable to the Lakeland project was $73 million. Beginning in 2002, EME reported the Lakeland

project among discontinued operations and accounts for its ownership of Lakeland Power on the cost method, with earnings being recognized as cash is distributed from the project.

On January 29, 2006, the main power transformer on Unit 3 of the Homer City facilities failed resulting in a suspension of operations at this unit. Homer City secured a replacement transformer and Unit 3 returned to service on May 5, 2006. The failure increased the forced outage rate during the quarter to 23% from 7% in the first quarter of 2005. Homer City has adjusted its previously planned outage schedules for Unit 3 and the other Homer City units in order to minimize to the extent practicable overall outage activities for all units through the first half of 2007. Although it had been anticipated that with the adjustment of outage schedules generation for the year as a whole would not be significantly affected, difficulties in transporting the new transformer to the site resulted in a longer outage than originally planned for the transformer repair. Taking into consideration the impact of the outage, generation for the year is currently expected to be approximately 13 terawatt hours (TWh). The actual financial impact and generation levels in 2006 will depend on the effect of market conditions upon the dispatch of the plant and on prevailing power prices during the balance of the year.

EME has engaged investment and commercial banks to undertake a refinancing of indebtedness. If effected, EME anticipates that the refinancing will include the following:

To effect its refinancing, EME will offer to purchase the outstanding senior notes referred to above. In connection with its offer, EME will solicit consents to amendments to the terms of the outstanding senior notes, including amendments necessary to permit EME to increase the size of its secured corporate credit facility. EME expects to pay a premium using its existing cash on hand to purchase the outstanding senior notes that are tendered and accepted for purchase. Its offer to purchase these outstanding senior notes will be conditioned upon the successful issuance of its new senior notes.

The refinancing is expected to improve EME’s liquidity, to extend the maturity dates of EME’s indebtedness, to reduce annual interest costs, and to improve the operating flexibility of the covenants associated with EME’s outstanding debt. Completion of this refinancing, if effected, will result in a significant charge against income for early retirement of the outstanding senior notes. There is no assurance that this or any other refinancing will be completed on the terms outlined above or at all.

As of March 31, 2006, SCE had cash and equivalents of $142 million ($80 million of which was held by SCE’s consolidated Variable Interest Entities). As of March 31, 2006, long-term debt, including current maturities of long-term debt, was $5.4 billion. In December 2005, SCE replaced its $1.25 billion credit facility with a $1.7 billion five-year senior secured credit facility. The security pledged (first and refunding mortgage bonds) for the new facility can be removed at SCE’s discretion. If SCE chooses to remove the security, the credit facility’s pricing will change to an unsecured basis per the terms of the credit facility agreement. As of March 31, 2006, SCE’s credit facility supported $269 million in letters of credit and $188 million of commercial paper outstanding, leaving $1.2 billion available under the credit facility.

SCE’s estimated cash outflows during the twelve-month period following March 31, 2006 consist of:

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

In April 2006, SCE issued $331 million of pollution-control bonds. The issuance included $196 million of 4.10% bonds due in April 2013 and $135 million of 4.25% bonds due in November 2016. The proceeds from the issuance of the bonds were used to call and redeem $196 million of pollution-control bonds due February 2008 and $135 million of pollution-control bonds due March 2008.

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

At March 31, 2006, SCE’s credit rating on long-term senior secured debt from Standard & Poor’s Rating Services and Moody’s Investors Service were BBB+ and A3, respectively. At March 31, 2005, SCE’s short-term (commercial paper) credit ratings from Standard & Poor’s and Moody’s were A-2 and P-2, respectively.

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, 2006, SCE’s 13-month weighted-average common equity component of total capitalization was 50%. At March 31, 2006, SCE had the capacity to pay $157 million in additional dividends based on the 13-month weighted-average method. Based on recorded March 31, 2006 balances, SCE’s common equity to total capitalization ratio, for rate-making purposes, was 49%. SCE had the capacity to pay $62 million of additional dividends to Edison International based on March 31, 2006 recorded balances.

SCE has a debt covenant in its credit facility that requires a debt to total capitalization ratio of less than or equal to 0.65 to 1 to be met. At March 31, 2006, SCE’s debt to total capitalization ratio was 0.46 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 and changes in market prices relative to contractual commitments, and other factors. At March 31, 2006, SCE had a net deposit of $189 million (comprised of $87 million in cash and reflected in “Margin and collateral deposits” on the balance sheet and $102 million in letters of credit) with a broker. In addition, SCE has deposited $187 million (comprised of $21 million in cash and reflected in “Margin and collateral deposits” on the balance sheet and $167 million in letters of credit) with other brokers and counterparties. Cash deposits with brokers and counterparties earn interest at various rates.

Margin and collateral deposits in support of power contracts and trading activities fluctuate with changes in market prices. Future margin and collateral requirements may be higher or lower than the margin collateral requirements as of March 31, 2006, based on future market prices and volumes of contractual and trading activity.

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

SCE’s 2006 GRC application requested a revised 2006 base rate revenue requirement of $3.96 billion, an increase of $325 million over SCE’s 2005 base rate revenue. The requested increase is primarily driven by capital expenditures needed to accommodate infrastructure replacement and customer and load growth, and higher operating and maintenance expenses, particularly in SCE’s transmission and distribution business unit. SCE also requested the CPUC continue SCE’s existing post-test year rate-making mechanism, which would result in further revised base rate revenue increases of $108 million in 2007 and $113 million in 2008.

On April 13, 2006, the CPUC assigned administrative law judge revised his January 17, 2006 proposed decision to correct several technical and substantive errors. On May 5, 2006, a third proposed decision was issued to increase authorized operating and maintenance expenses by an additional $45 million over the earlier revised proposed decision. The latest proposed decision would result in a 2006 base rate revenue requirement of $3.78 billion, an increase of $133 million over SCE’s 2005 base rate revenue, and further increases of $74 million in 2007 and $104 million in 2008. A final CPUC decision is expected in the second quarter of 2006. SCE cannot predict the final outcome of SCE’s GRC application.

On March 27, 2006, SCE initiated proceedings requesting the CPUC to waive the requirement that SCE file a 2007 cost of capital application and instead file its next such application in 2007 for year 2008. If SCE’s waiver

application is granted, SCE’s authorized capital structure, return on common equity of 11.6% and overall rate of return on capital of 8.77% will not change for 2007. SCE anticipates a CPUC decision on its waiver application by the fourth quarter of 2006.

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings” in the year-ended 2005 MD&A, the Energy Resource Recovery Account (ERRA) is the balancing account mechanism to track and recover SCE’s fuel and procurement-related costs. If the ERRA balancing account incurs an overcollection or undercollection in excess of 4% of SCE’s prior year’s generation revenue, the CPUC has established a “trigger” mechanism, whereby SCE must file an application in which it can request an emergency rate adjustment if the ERRA overcollection or undercollection exceeds 5% of SCE’s prior year’s generation revenue. In February 2006, the ERRA was undercollected by $206 million, which was 5.16% of SCE’s prior year’s generation revenue. On April 14, 2006 SCE filed an ERRA trigger application. In its application, SCE forecasts that the ERRA undercollection will be eliminated by the end of June 2006 as a result of the implementation of the CPUC’s January 2005 ERRA decision (see “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings—ERRA Forecast” in the year-ended 2005 MD&A for further discussion) and no further rate action by the CPUC would be necessary. A CPUC decision on this application is expected in June 2006. As of March 31, 2006, the ERRA was undercollected by $130 million, which was 3.27% of SCE’s prior year’s generation revenue.

On August 26, 2005, SCE filed an application for rehearing and a petition for modification of the CPUC’s July 21, 2005 decision. On January 26, 2006, the CPUC denied SCE’s application for rehearing of the decision. On April 20, 2006, the CPUC issued a draft decision denying SCE’s petition for modification. A decision is expected in the second quarter of 2006.

If SCE can only count the output deemed “incremental” by the CEC, SCE could have deficits in meeting its renewable procurement obligations for 2003 and 2004. However, based on the CPUC’s rules for compliance with renewable procurement targets, SCE may have until 2007 to make up these deficits before becoming subject to penalties for those years. The CEC’s and the CPUC’s treatment of the output from the geothermal facilities could also result in SCE being deemed to be out of compliance in 2005 and 2006. Under current CPUC decisions, potential penalties for SCE’s failure to achieve its renewable procurement obligations for any year will be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance filing. Under the CPUC’s current rules, the maximum penalty for failing to achieve renewables procurement targets is $25 million per year. SCE cannot predict whether it will be assessed penalties.

Mohave Generating Station (Mohave) obtained all of its coal supply from the Black Mesa Mine in northeast Arizona, located on lands of the Navajo Nation and Hopi Tribe (the Tribes). This coal was delivered from the mine to Mohave by means of a coal slurry pipeline, which requires water from wells located on lands belonging to the Tribes in the mine vicinity. Uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave co-owners from making approximately $1.1 billion in Mohave-related investments (SCE’s share is $605 million), including the installation of enhanced pollution-control equipment required by a 1999 air-quality consent decree in order for Mohave to operate beyond 2005. Accordingly, the plant ceased operations, as scheduled, on December 31, 2005, consistent with the provisions of the consent decree.

SCE continues to pursue all reasonable options to return Mohave to service in compliance with the consent decree. Negotiations, water studies, and other efforts among SCE and the other relevant parties continue in an attempt to resolve Mohave’s coal and water supply issues. Although progress has been made with respect to certain issues, no complete resolution has been reached to date. Assuming substantial resolution of the coal and water issues in 2006, and CPUC authorization of the necessary investments, SCE estimates that Mohave could return to service in approximately 2010. However, at this time, SCE does not know the length of the suspension period, and a permanent suspension remains possible. During the suspension period the absence of Mohave as an available resource will impact SCE’s resource requirements and resource planning.

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—San Onofre Nuclear Generating Station Steam Generators” in the year-ended 2005 MD&A, on December 15, 2005, the CPUC issued a final decision on SCE’s application for replacement of SCE’s San Onofre Units 2 and 3 steam generators. SCE provided its acceptance of the decision to the CPUC on March 6, 2006.

The city of Anaheim opted out of the project and agreed to transfer its 3.16% share of San Onofre to SCE. In March 2006, SCE filed applications to the Nuclear Regulatory Commission (NRC) and the Federal Energy Regulatory Commission (FERC) requesting authority to transfer Anaheim’s share to SCE. Also, in March 2006, SCE filed an application with the CPUC requesting rate recovery for Anaheim’s share of San Onofre operating and decommissioning costs. In April 2006, the FERC granted SCE authority to transfer Anaheim’s share to SCE. The transfer of Anaheim’s share is contingent upon receipt of regulatory approvals.

On April 13, 2006, SCE and San Diego Gas & Electric Company (SDG&E) settled a dispute regarding SDG&E’s decision to opt out of steam generator replacement. As a result, on April 14, 2006, SDG&E applied to the CPUC to participate in the steam generator replacement and retain its 20% share of San Onofre contingent upon CPUC adoption of its application subject to certain conditions including, operating and maintenance expense balancing account and an 11.6% return on equity for SDG&E’s San Onofre capital investment. If the CPUC’s decision is not acceptable to SDG&E, it may file an application with the CPUC to opt out of steam generator replacement and have its ownership share of San Onofre reduced.

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—FERC Refund Proceedings” in the year-ended 2005 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. In November 2005, SCE and other parties entered into a settlement agreement with Enron Corporation and a number of its affiliates (collectively Enron), most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In April 2006, SCE received a distribution on its allowed bankruptcy claim against one of the Enron debtors of approximately $29 million, and 196,245 shares of common stock of Portland General Electric Company with an aggregate value of approximately $5 million. In December 2005, the FERC approved a settlement agreement among SCE, Pacific Gas and Electric Company, SDG&E, several governmental

entities and certain other parties, and Reliant Energy, Inc. and a number of its affiliates. In January 2006, SCE received its $65 million share of the settlement proceeds. In March 2006, SCE received an additional $61 million. SCE is required to refund to customers 90% of any refunds actually realized by SCE, net of litigation costs, and 10% will be retained by SCE as a shareholder incentive.

Between December 2005 when Palo Verde Unit 1 returned to service from its refueling and steam generator replacement outage and March 21, 2006, Palo Verde Unit 1 operated at between 25% and 32% power level. The need to operate at a reduced power level was due to the vibration level in one of the unit’s shutdown cooling lines. On March 21, 2006, Arizona Public Service, the Operating Agent for Palo Verde Unit 1 decided to remove the unit from service completely until the vibration problem could be resolved. SCE expects that the outage will continue into late June. Incremental replacement power costs are expected to be recovered through the ERRA ratemaking mechanism.

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. See “SCE: Market Risk Exposures” in the year-ended 2005 MD&A for a complete discussion of SCE’s market risk exposures.

The following table summarizes the net fair values for outstanding physical and financial derivative investments used at SCE to mitigate its exposures to commodity price risk:

EMG has no business activities other than through its ownership interests in its subsidiaries, including MEHC (parent), EME, and Edison Capital. The following section includes discussion of liquidity, market risk exposures and other matters related to EMG’s principal subsidiaries.

For a complete discussion of these issues, read this quarterly report in conjunction with the year-ended 2005 MD&A.

At March 31, 2006, MEHC had cash and cash equivalents of $1 million (excluding amounts held by EME and its subsidiaries). MEHC’s ability to honor its obligations under the senior secured notes is substantially dependent upon the receipt of dividends from EME and the receipt of tax-allocation payments from EMG, and ultimately Edison International. See “—EME’s Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement.” Dividends to MEHC from EME are limited based on EME’s earnings and cash flow, terms of restrictions contained in EME’s corporate credit facility, business and tax considerations and restrictions imposed by applicable law.

At March 31, 2006, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.5 billion and EME had available the full amount of borrowing capacity under its $98 million corporate credit facility. EME’s consolidated debt at March 31, 2006 was $3.2 billion. In addition, EME’s subsidiaries had $4.5 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 29 years.

The estimated capital and construction expenditures of EME’s subsidiaries are $317 million for the remaining three quarters of 2006 and $232 million and $28 million for 2007 and 2008, respectively. The non-environmental

portion of these expenditures relates to the construction of the Wildorado wind project, purchases of turbines, upgrades to dust collection/mitigation systems and the coal handling system, ash removal improvements and various other projects. EME plans to finance these expenditures with existing subsidiary credit agreements, cash on hand or cash generated from operations. Included in the estimated expenditures are environmental expenditures of $5 million for the remaining three quarters of 2006, $12 million for 2007 and $6 million for 2008. The environmental expenditures relate to environmental projects such as selective catalytic reduction system improvements at the Homer City facilities and projects at the Illinois plants. EME’s subsidiaries may also make substantial additional capital expenditures as described in “Other Developments—Environmental Matters—Federal Air Quality Standards” of the year-ended 2005 MD&A. As part of these expenditures, EME Homer City is in the process of engaging a third party to commence preliminary engineering and advance procurements for pollution control equipment to be installed in late 2008 and 2009. A decision regarding whether to proceed with installation of this equipment is expected to be made later this year.

The credit ratings for MEHC and its subsidiaries, EME, Midwest Generation and Edison Mission Marketing & Trading (EMMT), are as follows:

MEHC 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. MEHC 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.

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

The Homer City sale-leaseback documents restrict EME Homer City’s ability to enter into trading activities, as defined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from Standard & Poor’s 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, 2006. EME Homer City continues to be in compliance with the terms of the consent; however, the consent is revocable by the sale- leaseback owner participant at any time. The sale-leaseback owner participant has not indicated that it intends to

revoke the consent; however, there can be no assurance that it will not do so in the future. Revocation of the consent would not affect trades between EMMT and EME Homer City that had been entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See “EMG: Market Risk Exposures—MEHC’s Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities.”

MEHC’s Margin, Collateral Deposits and Other Credit Support for Energy Contracts

In connection with entering into contracts in support of EME’s price risk management and energy trading activities (including forward contracts, transmission contracts and futures contracts), EME’s subsidiary, EMMT, has entered into agreements to mitigate the risk of nonperformance. Because the credit ratings of EMMT and EME are below investment grade, EME has historically provided collateral in the form of cash and letters of credit for the benefit of counterparties related to accounts payable and unrealized losses in connection with these price risk management and trading activities. At March 31, 2006, EMMT had deposited $411 million in cash with brokers in margin accounts in support of futures contracts and had deposited $178 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $21 million in support of commodity contracts at March 31, 2006.

Margin and collateral deposits increased during the past year due to higher wholesale energy prices and increased megawatt hours (MWh) hedged under contracts requiring margin and collateral. Future cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2006, if wholesale energy prices increase further or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of March 31, 2006 could increase by approximately $290 million using a 95% confidence level during the next twelve months.

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, 2006, Midwest Generation had available the full amount of borrowing capacity under this credit facility. As of March 31, 2006, Midwest Generation had $224 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and a $98 million working capital facility to provide credit support to subsidiaries. See “—EME’s Liquidity as a Holding Company” for further discussion.

At March 31, 2006, EME had corporate cash and cash equivalents and short-term investments of $1.3 billion to meet liquidity needs. See “—EME’s Liquidity.” Cash distributions from EME’s subsidiaries and partnership investments and unused capacity under its corporate credit facility represent EME’s major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME’s subsidiaries may be affected by many factors beyond its control. See “—MEHC’s Dividend Restrictions in Major Financings.”

As security for its obligations under EME’s corporate credit facility, EME pledged its ownership interests in the holding companies through which it owns its interests in the Illinois plants, the Homer City facilities, the Westside projects and the Sunrise project. EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects are deposited. EME is free to use these distributions unless and until an event of default occurs under its corporate credit facility.

At March 31, 2006, EME also had available $66 million under Midwest Generation EME, LLC’s $100 million letter of credit facility with Citibank, N.A., as Issuing Bank, that expires in December 2006. Under the terms of this letter of credit facility, Midwest Generation EME is required to deposit cash in a bank account in order to cash collateralize any letters of credit that may be outstanding under the facility. The bank account is pledged to the Issuing Bank. Midwest Generation EME owns 100% of Edison Mission Midwest Holdings, which in turn owns 100% of Midwest Generation, LLC.

During March 2006, EME, through its subsidiary, Edison Mission Finance, advanced funds in the amount of $9 million to EME Homer City under the subordinated revolving loan agreement in place between Edison Mission Finance and EME Homer City. The funds were used to assist EME Homer City with a cash shortfall resulting from reduced revenues and higher maintenance expenses caused by the Unit 3 outage. For similar reasons, at the end of March 2006 and April 2006, EMMT made advance payments to EME Homer City in the amounts of $43.5 million and $20 million, respectively, against future deliveries of power to it under its trading arrangements with EME Homer City. The proceeds of the subordinated loans were deposited in EME Homer City’s operating account and the prepayment by EMMT was deposited in EME Homer City’s revenue account. It is currently anticipated that a substantial portion of the advance payments will be applied against amounts invoiced to EMMT within the next 12 months.

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

MEHC (parent) and EME are included in the consolidated federal and combined state income tax returns of Edison International and are eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of MEHC (parent) and EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of MEHC (parent) and EME, respectively, in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of MEHC (parent), EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. MEHC (parent) and EME receive tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize MEHC (parent)’s tax losses or the tax losses of EME in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, MEHC (parent) and EME are obligated during periods they generate taxable income to make payments under the tax-allocation agreements. MEHC (parent) paid tax-allocation payments to Edison International of $2 million during the first quarter of 2005. EME paid tax-allocation payments to Edison International of $28 million and $20 million during the first quarters of 2006 and 2005, respectively.

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 MEHC and EME’s principal subsidiaries required by financing arrangements for the twelve months ended March 31, 2006:

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 “MEHC: Liquidity—Dividend Restrictions in Major Financings” in the year-ended 2005 MD&A.

Edison Capital’s main sources of liquidity are tax-allocation payments from Edison International, distributions from its global infrastructure fund investments and lease rents. During the first quarter of 2006, Edison Capital received $30 million in tax-allocation payments and $14 million in global infrastructure fund distributions.

As of March 31, 2006, Edison Capital had unrestricted cash and cash equivalents of $437 million and long-term debt, including current maturities, of $312 million (including intercompany-related debt).

At March 31, 2006, Edison Capital’s long-term debt had credit ratings of Ba1 and BB+ from Moody’s Investors Service and Standard & Poor’s, respectively.

Edison Capital’s ability to make dividend payments to Edison International (parent) is restricted by debt covenants (see “Edison International (Parent): Liquidity” for further discussion). During the first quarter of 2006, Edison Capital complied with its debt covenants.

Edison Capital is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in tax-allocation payments with Edison International and other subsidiaries of Edison International. See “EMG: Liquidity—EME’s Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement” for additional information regarding these arrangements. The amount received is net of payments made to Edison International. (See “Other Developments—Federal Income Taxes” for further discussion of tax-related issues regarding Edison Capital’s leveraged leases).

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

This section discusses these market risk exposures under the following headings:

For a complete discussion of these issues, read this quarterly report in conjunction with the year-ended 2005 MD&A).

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

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

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

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

EME uses “value at risk” to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois plants, its Homer City facilities, and its trading positions. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop loss limits and counterparty credit exposure limits.

To reduce its exposure to market risk, EME hedges a portion of its merchant portfolio risk through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its merchant portfolio, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented through the use of contracts cleared on the Intercontinental Trading Exchange and the New York Mercantile Exchange. Hedge transactions are also entered into as forward sales to utilities and power marketing companies.

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 sales at forward market prices are sufficiently attractive compared to assuming the risk associated with fluctuating spot market sales. Second, EME’s ability to enter into hedging transactions depends upon its, Midwest Generation’s and EMMT’s credit capacity and upon the forward sales markets having sufficient liquidity to enable EME to identify appropriate counterparties for hedging transactions.

In the case of hedging transactions related to the generation and capacity of the Illinois plants, Midwest Generation is permitted to use its working capital facility and cash on hand to provide credit support for these hedging transactions entered into by EMMT under an energy services agreement between Midwest Generation and EMMT. Utilization of this credit facility in support of hedging transactions provides additional liquidity

support for implementation of EME’s contracting strategy for the Illinois plants. In the case of hedging transactions related to the generation and capacity of the Homer City facilities, credit support is provided by EME pursuant to intercompany arrangements between it and EMMT. See “—Credit Risk,” below.

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

Prior to May 1, 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois plants were direct “wholesale customers” and broker arranged “over-the-counter customers.” Effective May 1, 2004, the transmission system of Commonwealth Edison was placed under the control of PJM as the Northern Illinois control area, and on October 1, 2004, the transmission system of AEP was integrated into PJM, linking eastern PJM and the Northern Illinois control areas of the PJM system and allowing the Illinois plants to be dispatched into the broader PJM market. Further, on April 1, 2005, the Midwest Independent Transmission System Operator (MISO) commenced operation, linking portions of Illinois, Wisconsin, Indiana, Michigan, and Ohio, as well as other states in the region, in the MISO, where there is a bilateral market and day-ahead and real-time markets based on locational marginal pricing similar to that of PJM.

Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing and is no longer required to arrange and pay separately for transmission when making sales to wholesale buyers within the PJM system. Hedging transactions related to the generation of the Illinois units are entered into at the Northern Illinois Hub in PJM, the AEP/Dayton Hub in PJM and, with the advent of the MISO, at the Cinergy Hub in the MISO. Because of proximity, the Illinois plants are primarily hedged with transactions at the Northern Illinois Hub, but from time to time may be hedged in limited amounts at the AEP/Dayton Hub and the Cinergy Hub. These trading hubs have been the most liquid locations for these hedging purposes. However, hedging transactions which settle at points other than the Northern Illinois Hub are subject to the possibility of basis risk. See “—Basis Risk” below for further discussion.

The PJM pool 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 2006 and 2005.

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, 2006:

The following table summarizes Midwest Generation’s hedge position (primarily based on prices at the Northern Illinois Hub) at March 31, 2006:

Electric power generated at the Homer City facilities is generally sold into the PJM market. The PJM pool 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 New York Independent System Operator (NYISO) markets.

The following table depicts the average historical market prices for energy per megawatt-hour in PJM during the first three months of 2006 and 2005:

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, 2006:

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

Sales made from the Illinois plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices 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 known as the PJM West Hub in the case of the Homer City facilities and for a settlement point known as the Northern Illinois Hub in the case of the Illinois plants. EME’s price risk management activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. EME’s revenue with respect to such forward contracts include:

Under the PJM market design, locational marginal pricing, which establishes market prices at specific locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by transmission constraints. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to by EME as “basis risk.” During the three months ended March 31, 2006, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub (EME Homer City’s primary trading hub) by an average of 11%, compared to 6% during the three months ended March 31, 2005. The monthly average difference during the twelve months ended March 31, 2006 ranged from zero to 20%, which occurred in August 2005. In contrast to the Homer City facilities, during the past 12 months, the prices at the Northern Illinois Hub were substantially the same as those at the individual busbars of the Illinois plants.

By entering into cash settled future contracts and forward contracts using the PJM West Hub and the Northern Illinois Hub (or other similar trading hubs) as the settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME has purchased 8.4 TWh of financial transmission rights and basis swaps in PJM for Homer City during the period April 1, 2006 through May 31, 2007, and may continue to purchase financial transmission rights and basis swaps in the future. 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 price risk management activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

The Illinois plants use approximately 18 million to 20 million tons of coal annually, primarily obtained from the Southern Powder River Basin of Wyoming. In addition, the Homer City facilities use approximately 5 million to 6 million tons of coal annually, obtained from mines located near the facilities in Pennsylvania. Coal purchases are made under a variety of supply agreements with terms ranging from one year to eight years. The following table summarizes the percent of expected coal requirements for the next five years that were under contract at March 31, 2006.

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which is purchased for the Homer City facilities, increased considerably during 2005. The price of NAPP coal (with 13,000 British Thermal units (Btu) per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) fluctuated between $44 per ton and $57 per ton during 2005, with a price of $45 per ton at March 17, 2006, as reported by the Energy Information Administration. The 2005 overall increase in the NAPP coal price was largely attributed to greater demand from domestic power producers and increased international shipments of coal to Asia. During the first quarter of 2006, the price of NAPP coal remained constant at $45 per ton. Prices of Powder River Basin (PRB) coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content), which is purchased for the Illinois plants, significantly increased in 2005 due to the curtailment of coal shipments during 2005 due to increased PRB coal demand from other regions (east), rail constraints (discussed below), higher oil and natural gas prices and higher prices for SO2 allowances. On March 17, 2006, the Energy Information Administration reported the price of coal to be $14.40 per ton, which compares to 2005 prices that ranged from of $6.20 per ton to $18.48 per ton. The price of coal decreased during the first quarter of 2006 from 2005 year-end prices due to lower prices for SO2 allowances and mild weather during the first quarter of 2006.

During 2005, the rail lines that bring coal from the PRB to EME’s Illinois plants were damaged from derailments caused by heavy rains. The railroads are in the process of making necessary repairs to the remaining PRB joint line. Repairs are expected to continue through most of 2006. Based on communication with the transportation provider, EME expects to continue receiving a sufficient amount of coal to generate power at historical levels while these repairs are being completed.

The federal Acid Rain Program requires electric generating stations to hold SO2 allowances, and Illinois and Pennsylvania regulations implemented the federal NOx SIP Call requirement. Under these programs, 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. 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.

The price of emission allowances, particularly SO2 allowances issued through the federal Acid Rain Program decreased during the first quarter of 2006 from 2005 year-end prices. The average price of purchased SO2 allowances decreased to $928 per ton during the first quarter of 2006 from $1,219 per ton during 2005. The decrease in the price of SO2 allowances during the first quarter of 2006 from 2005 year-end prices has been attributed to lower loads in January 2006 and a decline in natural gas prices. The price of SO2 allowances, determined by obtaining broker quotes and information from other public sources, was $675 per ton as of April 28, 2006.

For a discussion of environmental regulations related to emissions, refer to “Other Developments—Environmental Matters” of the year-ended 2005 MD&A.

In conducting EME’s price risk management 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.

EME measures credit risk exposure from counterparties of its merchant energy activities 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 price risk management 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, 2006, the amount of exposure, 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 long-term power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a long-term 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 markets or transact capacity on a bilateral basis. Sales into the PJM pool accounted for approximately 77% of EME’s consolidated operating revenue for the three months ended March 31, 2006. Moody’s Investor Service 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 members based upon a predetermined formula. At March 31, 2006, EME’s account receivable due from PJM was $68 million.

Interest rate changes affect the cost of capital needed to operate EME’s projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of MEHC’s consolidated long-term obligations (including current portion) was $4.4 billion at March 31, 2006, compared to the carrying value of $3.9 billion. The fair market value of MEHC’s parent only total long-term obligations was $940 million at March 31, 2006, compared to the carrying value of $792 million.

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

In assessing the fair value of EME’s non-trading derivative financial instruments, EME uses a variety of methods and assumptions based on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The following table summarizes the maturities and the related fair value, based on actively traded prices, of EME’s commodity price risk management assets and liabilities as of March 31, 2006:

The fair value of the commodity financial instruments related to energy trading activities as of March 31, 2006 and December 31, 2005, are set forth below:

The change in the fair value of trading contracts for the quarter ended March 31, 2006, was as follows:

Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated electric utility that EME’s subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME’s subsidiary recorded these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of March 31, 2006):

On August 31, 2005, PJM filed under sections 205 and 206 of the Federal Power Act a proposal for a reliability pricing model (RPM) to replace its existing capacity construct. The proposal offers RPM as a new capacity construct to address the deficiencies in PJM’s current structure in a comprehensive and integrated manner. On April 20, 2006, the FERC issued an Initial Order on RPM, finding that as a result of a combination of factors, PJM’s existing capacity construct is unjust and unreasonable as a long-term capacity solution, because it fails to set prices adequate to ensure energy resources to meet its reliability responsibilities. Although the FERC did not find that the RPM proposal, as filed by PJM, is the just and reasonable replacement for the current capacity construct because some elements of the proposal need further development and elaboration, it did find that certain elements of the RPM proposal, with some adjustment and clarification, may form the basis for a just and reasonable capacity market. Accordingly, in the order the FERC provided guidance on PJM’s RPM proposal, as well as other features that need to be included in a just and reasonable capacity market, and established further proceedings to resolve these issues.

On April 25, 2006, the FERC issued an order regarding the MISO’s “Revenue Sufficiency Guarantee” charges (RSG charges). The MISO’s business practice manuals and other instructions to market participants have stated, since the implementation of market operations in April 1, 2005, that RSG charges will not be imposed on offers to supply power not supported by actual generation (also known as virtual supply offers). However, some market participants raised questions about the language of the MISO’s tariff concerning that issue and in October 2005, the MISO submitted to the FERC proposed tariff revisions clarifying its tariff to reflect its business practices with respect to RSG charges, and filed corrected tariff sheets exempting virtual supply from RSG charges. In its April 25 decision, the FERC interpreted the MISO’s tariff to require that virtual supply offers must be included in the calculation of the RSG charges and that to the extent that the MISO did not charge virtual supply offers for RSG charges, it violated the terms of its tariff. The FERC order then proceeded to require the MISO to recalculate the RSG charges back to April 1, 2005, and to make refunds to customers, with interest, reflecting the recalculated charges. In order to make such refunds, it is likely that the MISO will attempt to impose retroactively RSG charges on those who submitted virtual supply offers during the recalculation period. EMMT made virtual supply offers in the MISO during this period on which no RSG charges were imposed, and thus may be subject to a claim for refunds from the MISO (which claim will be contested by EMMT). Because calculation of any claimed liability for refunds depends on information not currently available to it, EMMT cannot reasonably estimate a range of loss related to this matter. In addition, it is likely that the FERC’s April 25 order will be challenged by the MISO and other parties, including EMMT, and the eventual outcome of these proceedings is unclear. The FERC’s order also requires the MISO to modify its tariff on a prospective basis to impose RSG charges on virtual supply offers. At this time, it is not possible to predict how the prospective effect of the order will affect the nature and operation of the MISO markets.

On May 1, 2006, the FERC issued an order in response to a complaint filed by Pepco Holdings, Inc. against PJM regarding marginal losses for transmission. The FERC concluded that PJM has violated its tariff by not implementing marginal losses and further directed PJM to implement marginal losses by October 2, 2006. Implementation of marginal losses will adjust the algorithm that calculates locational marginal prices to include a marginal loss component in addition to the already included congestion component. This may have an adverse impact on sellers in the Western PJM region. At this time, it is not possible to predict how the prospective effect of the order will affect the prices at which EME Homer City and Midwest Generation will be able to sell their power. In addition, PJM is still in the process of determining if it is technically feasible to implement marginal losses by October 2, 2006.

Edison Capital is exposed to interest rate risk, foreign currency exchange rate risk and credit and performance risk that could adversely affect its results of operations or financial position. See “Edison Capital: Market Risk Exposures” in the year-ended 2005 MD&A for a complete discussion of Edison Capital’s market risk exposures.

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

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, 2006, Edison International had no debt outstanding (excluding intercompany related debt).

Edison International (parent)’s cash requirements for the twelve-month period following March 31, 2006 primarily consist of:

Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand, short-term borrowings, when necessary, and dividends from its subsidiaries. At March 31, 2006, Edison International (parent) had approximately $79 million of cash and cash equivalents on hand. In December 2005, Edison International (parent) replaced its $750 million credit facility with a $1 billion five-year senior unsecured credit facility. As of March 31, 2006, the entire $1 billion 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.

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. The CPUC also requires that SCE establish its dividend policy as though it were a comparable stand-alone utility company and give first priority to the capital requirements of the utility as necessary to meet its obligation to serve its customers. Other factors at SCE that affect the amount and timing of dividend payments by SCE to Edison International include, among other things, SCE’s capital requirements, SCE’s access to capital markets, payment of dividends on SCE’s preferred and preference stock, and actions by the CPUC. During the first quarter of 2006, SCE made a dividend payment of $71 million to Edison International on January 17, 2006. On March 1, 2006, the Board of Directors of SCE declared a $60 million dividend to Edison International which was paid on April 28, 2006. On April 27, 2006, the Board of Directors of SCE declared an additional $60 million dividend payable to Edison International.

MEHC may not pay dividends unless it has an interest coverage ratio of at least 2.0 to 1. At March 31, 2006, its interest coverage ratio was 2.83 to 1. See “EMG: Liquidity—MEHC’s Dividend Restrictions in Major Financings—Key Ratios of MEHC and EME’s Principal Subsidiaries Affecting Dividends.” In addition, MEHC’s certificate of incorporation and senior secured note indenture contain restrictions on MEHC’s ability to declare or pay dividends or distributions (other than dividends payable solely in MEHC’s common stock). These restrictions require the unanimous approval of MEHC’s Board of Directors, including its independent director, before it can declare or pay dividends or distributions, as long as any indebtedness is outstanding under the indenture. MEHC’s ability to pay dividends is dependent on EME’s ability to pay dividends to MEHC (parent). MEHC has not declared or made dividend payments to Edison International during the first quarter of 2006. EME and its subsidiaries have certain dividend restrictions as discussed in the “EMG: Liquidity—MEHC’s Dividend Restrictions in Major Financings” section.

Edison Capital’s ability to make dividend payments is currently restricted by covenants in its financial instruments, which require Edison Capital, through a wholly owned subsidiary, to maintain a specified minimum net worth of $200 million. Edison Capital satisfied this minimum net worth requirement as of March 31, 2006. Edison Capital did not declare or make dividend payments to Edison International in the first quarter of 2006.

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

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

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

Edison International recorded consolidated earnings of $258 million, or 78¢ per common share, in first quarter 2006, compared to $201 million, or 61¢ per common share, in first quarter 2005. The increase in consolidated earnings in 2006 was due to the receipt of distributions from the Lakeland project in administrative receivership in the U.K. and higher wholesale margins driven by higher energy prices at MEHC, partially offset by the impact from the delay in the 2006 GRC decision at SCE, and at EMG, gains recorded in the first quarter of 2005 from Edison Capital’s Emerging Europe Infrastructure Fund, along with an outage at MEHC’s Homer City facilities.

The table below presents Edison International’s earnings and earnings per common share for the three-month periods ended March 31, 2006 and 2005, and the relative contributions by its subsidiaries.

Edison International’s first quarter 2006 earnings from continuing operations were $184 million, or 56¢ per common share, compared with earnings of $194 million, or 59¢ per common share in first quarter 2005.

SCE’s first quarter 2006 earnings from continuing operations were $121 million, compared with $131 million in first quarter 2005. The decrease is primarily due to the impact of higher operating costs associated with the utility’s customer and system growth and the delay in receiving the 2006 GRC decision. When the 2006 GRC decision is issued, SCE will be authorized by the CPUC to recover its revenue requirement retroactive to

January 12, 2006. The decrease in SCE’s earnings was partially offset by the return on investment earned by SCE’s newly constructed Mountainview plant.

EMG’s first quarter 2006 earnings from continuing operations were $73 million, compared to $76 million in first quarter 2005. MEHC’s 2006 first quarter earnings from continuing operations were $56 million, an increase of $31 million from the same period last year. MEHC’s increase was primarily due to higher wholesale energy margins driven by higher prices at the Illinois plants and higher interest and other income, partially offset by lower generation and higher maintenance expense at Homer City in 2006 due to a transformer failure at Unit 3 on January 29, 2006, and a $15 million after-tax charge related to the early extinguishment of debt at MEHC recorded in the first quarter 2005. Edison Capital’s earnings were $17 million in the first quarter of 2006, down $34 million from the same period last year. Edison Capital’s decrease in earnings was largely due to 2005 gains from Edison Capital’s investment in the Emerging Europe Infrastructure Fund.

The first quarter 2006 loss from Edison International (parent) and other of $10 million was $3 million lower than the same period last year, primarily reflecting lower tax expense.

SCE’s retail sales represented approximately 85% and 80% of electric utility revenue for the first quarter of 2006 and 2005, respectively. Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is generally significantly higher than other quarters.

Total electric utility revenue increased by $309 million in 2006 (as shown in the table above). The increase resulting from rate changes was due to the rate change implemented on February 4, 2006 arising from SCE’s 2006 ERRA decision (see “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings—ERRA Forecast” in the year-ended 2005 MD&A for further discussion). The increase in electric utility revenue resulting from sales volume changes was mainly due to an increase in kilowatt-hours (kWh) sold, including SCE providing a greater amount of energy to its customers from its own sources in 2006, compared to 2005. The change in deferred revenue reflects the recognition of approximately $107 million of revenue in 2006, resulting from balancing account undercollections, compared to the deferral of approximately $78 million of revenue in 2005. Electric utility revenue from sales for resale represents the sale of excess energy. Excess energy from SCE sources may exist at certain times, which then is resold in the energy markets. Sales for resale revenue decreased due to a lesser amount of excess energy in the first quarter of 2006, as compared to the same period in 2005. Revenue from sales for resale is refunded to customers through the ERRA rate-making mechanism and does not impact earnings. SCE’s variable interest entities revenue represents the recognition of revenue resulting from the consolidation of SCE’s variable interest entities.

Amounts SCE bills and collects from its customers for electric power purchased and sold by the California Department of Water Resources (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 $568 million and $510 million for the three-month periods ended March 31, 2006 and 2005, respectively.

Nonutility power generation revenue decreased slightly in 2006, as compared to 2005, mainly due to lower energy revenue and increased losses from price risk management and trading activities at MEHC’s Homer City facilities, offset by higher energy revenue and decreased losses from price risk management and trading activities at MEHC’s Illinois plants, and higher energy trading income from Edison Mission Marketing & Trading.

Energy revenue at MEHC’s Homer City facilities decreased $21 million in the first quarter of 2006, as compared to the first quarter of 2005, primarily due to an unplanned outage at Unit 3 in the first quarter of 2006 (see “Current Developments—EMG: Current Developments—MEHC: Homer City Transformer Failure” for further discussion). Homer City is generally classified as a baseload plant which means the amount of generation is largely based on the availability of the plant. Accordingly, the Unit 3 outage reduced the amount of expected generation during the first quarter of 2006. Losses from price risk management and trading activities at MEHC’s Homer City facilities increased $12 million for the first quarter of 2006, compared to the first quarter of 2005, attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under the accounting standard for derivative instruments and hedging activities. MEHC’s Homer City facilities recorded losses of approximately $11 million and $4 million during the first quarters of 2006 and 2005, respectively, representing the amount of cash flow hedges’ ineffectiveness. The 2006 ineffective losses from MEHC Homer City facilities are related to the remainder of 2006 and 2007 hedge contracts and were primarily attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). See “EMG: Market Risk Exposures—MEHC’s Commodity Price Risk” for more information regarding forward market prices.

Energy revenue at MEHC’s Illinois plants increased $11 million due to higher average energy prices, partially offset by lower generation. Although generation in the first quarter of 2006 was lower than the first quarter of 2005, gross margin increased 12% primarily due to a 20% increase in average energy prices. Losses from price risk management and trading activities at MEHC’s Illinois plants decreased $10 million for the first quarter 2006, as compared to the first quarter 2005. The 2005 losses were primarily due to significant price increases in 2005 on power contracts that did not qualify for hedge accounting.

Revenue from energy trading activities at EMMT increased $8 million in the first quarter of 2006, as compared to the first quarter of 2005. The increase was primarily due to increased congestion at specific delivery points in the eastern power grid in which EMMT purchased financial transmission rights. See “EMG: Market Risk Exposures—Regulatory Matters—MISO Revenue Sufficiency Guarantee Charge” for information regarding potential refund exposure related to virtual supply offers made by EMMT in MISO after April 1, 2005.

Due to higher electric demand resulting from warmer weather during the summer months, nonutility power generation revenue generated from MEHC’s Illinois plants and Homer City facilities are generally higher during the third quarter of each year. However, as a result of recent increases in market prices for power, driven in part by higher natural gas and oil prices, this historical trend may not be applicable to quarterly revenue in the future.

SCE’s fuel expense increased $56 million for the three-month period ended March 31, 2006. The 2006 increase was primarily due to $55 million of fuel expense in the first quarter of 2006 resulting from SCE’s newly constructed Mountainview project which became operational in December 2005, and increased fuel expense related to SCE’s consolidated variable interest entities. Fuel expense related to SCE’s consolidated variable interest entities was $225 million and $193 million for the three-month periods ended March 31, 2006 and 2005, respectively. The increase in fuel expense was partially offset by a decrease in fuel expense of approximately $15 million at SCE’s Mohave Generating Station resulting from the electric generation operations being ceased on December 31, 2005 (see “SCE: Regulatory Matters—Mohave Generating Station and Related Proceedings” for further discussion), lower nuclear fuel expense of approximately $5 million resulting from a planned refueling and maintenance outage at SCE’s San Onofre Unit 2 and a Department of Energy settlement refund of approximately $10 million related to crude oil overcharges. The settlement refund is returned to ratepayers through the ERRA mechanism.

MEHC’s fuel expense decreased $14 million for the three-month period ended March 31, 2006 primarily due to lower coal consumption resulting from lower generation at MEHC’s Illinois plants and Homer City facilities.

Purchased-power expense increased $625 million for the three-month period ended March 31, 2006. The 2006 increase was mainly due to net realized and unrealized losses on economic hedging transactions and higher firm energy and qualifying facilities (QF) related purchases. Net realized and unrealized losses related to economic hedging transactions increased purchased-power expense by approximately $410 million in 2006, as compared to net realized and unrealized gains of approximately $150 million which decreased purchased-power expense in 2005. Firm energy purchases increased by approximately $30 million primarily resulting from an increase in prices in 2006, as compared to 2005, and QF-related purchases increased by approximately $50 million in 2006, as compared to 2005 (as discussed below). The consolidation of SCE’s variable interest entities resulted in a $190 million and a $175 million reduction in purchased-power expense for the three-month periods ended March 31, 2006 and 2005, respectively.

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. Effective May 2002, energy payments for most renewable QFs were converted to a fixed price of 5.37¢-per-kWh until April 2007. Average spot natural gas prices were higher during 2006 as compared to 2005. The higher expenses related to power purchased from QFs were mainly due to higher average spot natural gas prices, partially offset by lower kWh purchases.

Provisions for regulatory adjustment clauses – net decreased $428 million for the three-month period ended March 31, 2006. The 2006 decrease was mainly due to higher net unrealized losses of approximately $490 million related to economic hedging transactions (mentioned above in purchased-power expense) that, if realized, would be recovered from ratepayers, partially offset by lower net undercollections of purchased-power, fuel, and operation and maintenance expenses of approximately $50 million resulting from rate increases implemented in April 2005 and February 2006, and the recognition of previously deferred revenue.

SCE’s other operation and maintenance expense increased $14 million in the first quarter of 2006, as compared to the first quarter in 2005. The 2006 increase was mainly due to higher generation-related costs of approximately $30 million primarily resulting from the planned refueling and maintenance outage at SCE’s San Onofre Unit 2 and an increase in demand-side management costs of approximately $10 million, partially offset by a decrease in reliability costs of approximately $30 million resulting from a decrease in must-run units. Demand-side management and reliability costs are recovered through regulatory mechanisms approved by the CPUC and the FERC, respectively.

SCE’s depreciation, decommissioning and amortization expense increased $31 million in the first quarter of 2006. The increase in 2006 is mainly due to an increase in depreciation expense resulting from additions to transmission and distribution assets, and higher investment earnings from SCE’s nuclear decommissioning trusts. The earnings are also recorded in electric utility revenue. As a result, nuclear decommissioning trust earnings have no impact on net income.

SCE’s interest and dividend income increased in the first quarter of 2006, as compared to the first quarter of 2005. The 2006 increase was mainly due to higher interest income resulting from higher balancing account undercollections and higher short-term interest rates in 2006 as compared to 2005.

MEHC’s interest and dividend income increased in the first quarter of 2006, as compared to the first quarter of 2005, primarily due to higher interest income earned on cash balances and short-term investments.

Equity in income from partnerships and unconsolidated subsidiaries – net decreased $81 million for the three-month period ended March 31, 2006. The 2006 decrease is mainly due to lower earnings of approximately $65 million from Edison Capital’s global infrastructure funds.

SCE’s other nonoperating income increased in the first quarter of 2006, as compared to the first quarter of 2005, mainly due to an increase in incentive rewards related to the efficient operation of Palo Verde and corporate-owned life insurance proceeds. The incentive rewards approved by the CPUC for the efficient operation of Palo Verde were $13 million in the first quarter of 2006 and $10 million in the first quarter of 2005.

MEHC’s other nonoperating income increased in the first quarter of 2006, as compared to the first quarter of 2005, mainly due to an $8 million gain related to the receipt of shares from Mirant Corporation from settlement of a claim.

Loss on early extinguishment of debt in the first quarter of 2005 primarily consisted of a $20 million loss related to the early repayment of the remaining balance of MEHC’s $385 million term loan.

Edison International’s effective tax rate from continuing operations was 38% for the three-month period ended March 31, 2006 as compared to 35% for the three-month period ended March 31, 2005. The increased effective tax rate resulted from reductions made to accrued tax liabilities at SCE in 2005 exceeding reductions made to accrued tax liabilities in 2006. The reductions in both periods were made to reflect progress made in settlement negotiations relating to prior-year tax liabilities. This increase was partially offset by a reduction in non-deductible compensation paid by Edison International between the periods.

Edison International’s earnings from discontinued operations were $73 million in the first quarter of 2006 reflecting the receipt of a distribution from the U.K. Lakeland project previously owned by MEHC (see “EMG: Current Developments—MEHC: Lakeland Project” for further discussion). The earnings from discontinued operations in the first quarter of 2005 of $7 million represent the operating results and sales impacts from MEHC’s Tri-Energy and CBK international projects.

Effective January 1, 2006, Edison International adopted a new accounting standard that requires the fair value accounting method for stock-based compensation. Implementation of this new accounting standard resulted in a $1 million, after-tax, cumulative-effect adjustment in the first quarter of 2006 (see “New Accounting Pronouncements” for further discussion).

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

The 2006 change in cash provided by operating activities from continuing operations was mainly due to a change in working capital items resulting from the timing of cash receipts and disbursements.

Cash provided by operating activities from discontinued operations increased $72 million in the first quarter of 2006, compared to the first quarter of 2005. The 2006 increase reflects distributions received in 2006 that were authorized by the liquidators of MEHC’s Lakeland power project. See “Current Developments—EMG: Current Developments—MEHC: Lakeland Project” for more information regarding these distributions.

Cash used by financing activities from continuing operations mainly consisted of long-term and short-term debt payments at SCE and EME.

Financing activities in the first quarter of 2006 included activities related to the rebalancing of SCE’s capital structure and rate base growth and the reduction of debt at MEHC. SCE’s first quarter 2006 financing activity included the issuance of $500 million of first and refunding mortgage bonds. The issuance included $350 million of 5.625% bonds due in 2036 and $150 million of floating rate bonds due in 2009. The proceeds were used to redeem $150 million of variable rate first and refunding mortgage bonds due in January 2006 and $200 million of its 6.375% first and refunding mortgage bonds due in January 2006. In addition, in January 2006, SCE issued two million shares of 6% Series C preference stock (non-cumulative, $100 liquidation value) and received net proceeds of $197 million. MEHC’s first quarter 2006 financing activity included the repayment of $170 million on Midwest Generation’s $500 million working capital facility. Financing activities in 2006 also include dividend payments of $88 million paid by Edison International to its shareholders.

Financing activities in the first quarter of 2005 included activities related to the rebalancing of SCE’s capital structure and the reduction of debt at MEHC. SCE’s first quarter 2005 financing activity included the issuance of $650 million of first and refunding mortgage bonds. The issuance included $400 million of 5% bonds due in 2016 and $250 million of 5.55% bonds due in 2036. The proceeds were used to redeem the remaining $50,000 of its 8% first and refunding mortgage bonds due February 2007 (Series 2003A) and $650 million of the $966 million 8% first and refunding mortgage bonds due February 2007 (Series 2003B). MEHC’s first quarter financing activity included the repayment of the remaining $285 million of the term loan and the repayment of the junior subordinated debentures of $150 million. Financing activities in 2005 also include dividend payments of $81 million paid by Edison International to its shareholders.

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

Investing activities in the first quarter of 2006 reflect $494 million in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $17 million for nuclear fuel acquisitions and approximately $4 million related to the Mountainview project, and $21 million in capital expenditures at MEHC.

Investing activities in the first quarter of 2005 reflect $364 million in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $14 million for nuclear fuel acquisitions and approximately $50 million related to the Mountainview project, and $14 million in capital expenditures at MEHC. Investing activities also include $124 million in proceeds received in 2005 from the sales of EME’s 25% investment in the Tri Energy project and EME’s 50% investment in the CBK project.

standard resulted in the recognition of expense for all stock-based compensation awards. Prior to January 1, 2006, Edison International used the intrinsic value method of accounting, which resulted in no recognition of expense for its stock options.

Prior to adoption of the new accounting standard, Edison International presented all tax benefits of deductions resulting from the exercise of stock options as a component of operating cash flows under the caption “Other liabilities” in the consolidated statements of cash flows. The new accounting standard requires the cash flows resulting from the tax benefits that occur from estimated tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. The $8 million excess tax benefit is classified as a financing cash inflow in 2006.

The following is an update to Edison International’s commitments, guarantees and indemnities. See the section, “Commitments, Guarantees and Indemnities,” in the year-ended 2005 MD&A for a detailed discussion.

At March 31, 2006, EME’s subsidiaries had firm commitments to spend approximately $163 million during the remainder of 2006 and $35 million in 2007 on capital and construction expenditures. The majority of these expenditures relate to the construction of the Wildorado wind project (see further discussion related to the Wildorado project in “Acquisition and Disposition”). Also included are expenditures for boiler head replacement, dust collection and mitigation system and various other projects. These expenditures are planned to be financed by existing subsidiary credit agreements, cash on hand or cash generated from operations.

Edison International is subject to numerous federal and state 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 existing environmental regulatory requirements.

Edison International’s domestic power plants, in particular its 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 sulfur dioxide and nitrogen oxide emissions, mercury emissions, ozone and fine particulate matter emissions, regional haze, water quality, and climate change, may require significant capital expenditures at its facilities. The developments in certain of these laws and regulations will continue to be monitored to assess

what implications, if any, they will have on the operation of domestic power plants owned or operated by SCE, EME, or their subsidiaries, or the impact on Edison International’s results of operations or financial position.

For a discussion of Edison International’s environmental matters, refer to “Other Developments—Environmental Matters” in the year-ended 2005 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 March 14, 2006, the Illinois Environmental Protection Agency submitted a proposed rule to the Illinois Pollution Control Board (PCB) for adoption. The proposed rule requires a reduction of mercury emissions from coal-fired power plants by 90% averaged across company-owned Illinois stations and a minimum reduction of 75% for individual generating units by July 1, 2009. A 90% reduction at each station would be required by 2013. The PCB has scheduled hearings for June and August 2006.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $29 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $55 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994–1996 and 1997–1999 tax years, respectively. Many of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of penalties), if any, would be deductible on future tax returns of Edison International.

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

sustained by the IRS would have a material impact on earnings. As of March 31, 2006, the interest on the proposed tax adjustments (excluding penalties) is estimated to be $346 million. Moreover, the FASB is currently considering changes to the accounting for leveraged leases which, if adopted, will be applicable to those leases where the tax treatment or the timing of the realization of tax benefits associated with them is altered. Under the proposed accounting rule, a change in the timing of expected cash flows related to these lease, including the realization of the tax benefits, would require the recalculation of the income allocated over the life of the lease, with the cumulative effect of the change recognized immediately. This could result in a material charge against earnings, although future income would be expected to increase over the remaining terms of the affected leases.

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,” “EMG: Market Risk Exposures,” and “Edison International (Parent): 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)


Class		Outstanding at April 30, 2006
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, 2006 and 2005	1

	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2006 and 2005	2

	Consolidated Balance Sheets – March 31, 2006 and December 31, 2005	3

	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2006 and 2005	5

	Notes to Consolidated Financial Statements	7

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	70

Item 4.	Controls and Procedures	70

Part II. Other Information:

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	71

Item 6.	Exhibits	72

Signature		73


	Three Months Ended March 31,
In millions, except per-share amounts	2006			2005
	(Unaudited)
Electric utility	$	2,217		$	1,908
Nonutility power generation		510			511
Financial services and other		24			27
Total operating revenue		2,751			2,446
Fuel		461			419
Purchased power		1,013			388
Provisions for regulatory adjustment clauses – net		(363	)		65
Other operation and maintenance		830			815
Depreciation, decommissioning and amortization		292			259
Property and other taxes		56			52
Total operating expenses		2,289			1,998
Operating income		462			448
Interest and dividend income		36			21
Equity in income from partnerships and unconsolidated subsidiaries – net		4			84
Other nonoperating income		42			18
Interest expense – net of amounts capitalized		(200	)		(214	)
Loss on early extinguishment of debt		—			(24	)
Other nonoperating deductions		(12	)		(10	)
Income from continuing operations before tax and minority interest		332			323
Income tax		111			104
Dividends on utility preferred and preference stock not subject to mandatory redemption		12			1
Minority interest		25			24
Income from continuing operations		184			194
Income from discontinued operations – net of tax		73			7
Income before accounting change		257			201
Cumulative effect of accounting change – net of tax		1			—
Net income	$	258		$	201

Weighted-average shares of common stock outstanding		326			326
Basic earnings per common share:
Continuing operations	$	0.56		$	0.59
Discontinued operations		0.22			0.02
Total	$	0.78		$	0.61

Weighted-average shares, including effect of dilutive securities		331			331
Diluted earnings per common share:
Continuing operations	$	0.56		$	0.59
Discontinued operations		0.22			0.02
Total	$	0.78		$	0.61
Dividends declared per common share	$	0.27		$	0.25


	Three Months Ended March 31,
In millions	2006			2005
	(Unaudited)
Net income	$	258		$	201
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) on cash flow hedges:
Other unrealized gain (loss) on cash flow hedges – net		187			(70	)
Reclassification adjustment for loss included in net income		(30	)		(5	)
Other comprehensive income (loss)		157			(75	)
Comprehensive income	$	415		$	126


In millions	March 31, 2006			December 31, 2005
	(Unaudited)
ASSETS
Cash and equivalents	$	1,897		$	1,893
Restricted cash		54			60
Margin and collateral deposits		567			739
Receivables, less allowances of $32 and $33 for uncollectible accounts at respective dates		889			1,220
Accrued unbilled revenue		274			291
Fuel inventory		122			80
Materials and supplies		270			261
Accumulated deferred income taxes – net		—			218
Trading and price risk management assets		142			316
Regulatory assets		829			536
Other current assets		391			345
Total current assets		5,435			5,959
Nonutility property – less accumulated provision for depreciation of $1,474 and $1,424 at respective dates		4,157			4,119
Nuclear decommissioning trusts		2,984			2,907
Investments in partnerships and unconsolidated subsidiaries		412			426
Investments in leveraged leases		2,464			2,447
Other investments		110			115
Total investments and other assets		10,127			10,014
Utility plant, at original cost:
Transmission and distribution		16,929			16,760
Generation		1,443			1,370
Accumulated provision for depreciation		(4,868	)		(4,763	)
Construction work in progress		1,090			956
Nuclear fuel, at amortized cost		153			146
Total utility plant		14,747			14,469
Restricted cash		100			105
Margin and collateral deposits		130			137
Trading and price risk management assets		131			132
Regulatory assets		3,023			3,013
Other long-term assets		958			951
Total long-term assets		4,342			4,338
Assets of discontinued operations		—			11

Total assets	$	34,651		$	34,791


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


In millions, except share amounts	March 31, 2006			December 31, 2005
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Short-term debt	$	188		$	—
Long-term debt due within one year		391			745
Accounts payable		734			961
Accrued taxes		293			262
Accrued interest		215			212
Counterparty collateral		30			183
Customer deposits		184			183
Book overdrafts		182			257
Accumulated deferred income taxes – net		50			—
Trading and price risk management liabilities		385			418
Regulatory liabilities		505			681
Other current liabilities		908			1,057
Total current liabilities		4,065			4,959
Long-term debt		9,045			8,833
Accumulated deferred income taxes – net		5,278			5,256
Accumulated deferred investment tax credits		128			130
Customer advances and other deferred credits		1,090			1,179
Trading and price risk management liabilities		163			101
Power-purchase contracts		55			64
Accumulated provision for pensions and benefits		771			745
Asset retirement obligations		2,649			2,628
Regulatory liabilities		3,009			2,962
Other long-term liabilities		285			285
Total deferred credits and other liabilities		13,428			13,350
Liabilities of discontinued operations		—			14
Total liabilities		26,538			27,156
Commitments and contingencies (Notes 3 and 4)
Minority interest		298			301
Preferred and preference stock of utility not subject to mandatory redemption		916			719
Common stock, no par value (325,811,206 shares outstanding at each date)		2,023			2,043
Accumulated other comprehensive loss		(69	)		(226	)
Retained earnings		4,945			4,798
Total common shareholders’ equity		6,899			6,615

Total liabilities and shareholders’ equity	$	34,651		$	34,791


	Three Months Ended March 31,
In millions	2006			2005 Revised⁽¹⁾
	(Unaudited)
Cash flows from operating activities:
Net income	$	258		$	201
Less: income from discontinued operations		73			7
Income from continuing operations		185			194
Adjustments to reconcile to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax		(1	)		—
Depreciation, decommissioning and amortization		292			259
Other amortization		21			22
Minority interest		25			24
Deferred income taxes and investment tax credits		115			34
Equity in income from partnerships and unconsolidated subsidiaries		(4	)		(84	)
Income from leveraged leases		(17	)		(18	)
Regulatory assets – long-term		38			170
Regulatory liabilities – long-term		(8	)		(70	)
Loss on early extinguishment of debt		—			24
Levelized rent expense		(49	)		(5	)
Other assets		6			(65	)
Other liabilities		54			25
Margin and collateral deposits – net of collateral received		28			(7	)
Receivables and accrued unbilled revenue		347			14
Trading and price risk management assets – short-term		188			(116	)
Inventory, prepayments and other current assets		(43	)		(79	)
Regulatory assets – short-term		(293	)		(294	)
Regulatory liabilities – short-term		(177	)		352
Accrued interest and taxes		36			21
Accounts payable and other current liabilities		(206	)		(97	)
Distributions and dividends from unconsolidated entities		2			14
Operating cash flows from discontinued operations		69			(3	)
Net cash provided by operating activities		608			315
Cash flows from financing activities:
Long-term debt issued and issuance costs		495			640
Long-term debt repaid		(578	)		(1,208	)
Issuance of preference stock		196			—
Redemption of preferred stock		—			(4	)
Rate reduction notes repaid		(62	)		(62	)
Change in book overdrafts		(76	)		(38	)
Short-term debt financing – net		188			202
Shares purchased for stock-based compensation		(77	)		(31	)
Proceeds from stock option exercises		21			20
Excess tax benefits related to stock option exercises		9			—
Dividends to minority shareholders		(41	)		(29	)
Dividends paid		(88	)		(81	)
Net cash used by financing activities	$	(13	)	$	(591	)


In millions	March 31, 2006		December 31, 2005
		(Unaudited)
Current:
Regulatory balancing accounts	$	475	$	355
Direct access procurement charges		107		113
Energy derivatives		142		—
Purchased-power settlements		45		53
Other		60		15
		829		536
Long-term:
Flow-through taxes – net		1,141		1,066
Rate reduction notes – transition cost deferral		413		465
Unamortized nuclear investment – net		476		487
Nuclear-related asset retirement obligation investment – net		288		292
Unamortized coal plant investment – net		96		97
Unamortized loss on reacquired debt		318		323
Direct access procurement charges		26		40
Energy derivatives		94		58
Environmental remediation		55		56
Purchased-power settlements		31		39
Other		85		90
		3,023		3,013
Total regulatory assets	$	3,852	$	3,549


	Three Months Ended March 31,
In millions, except per-share amounts	2005
		(Unaudited)
Net income, as reported	$	201
Add: stock-based compensation expense using the intrinsic value accounting method – net of tax		11
Less: stock-based compensation expense using the fair-value accounting method – net of tax		10
Pro forma net income	$	202
Basic EPS:
As reported	$	0.61
Pro forma	$	0.62

Diluted EPS:
As reported	$	0.61
Pro forma	$	0.61


	For the Three Months Ended March 31,
	2006	2005
	(Unaudited)
Expected terms (in years)	9 to 10	9 to 10
Risk-free interest rate	4.3%	4.2% – 4.3%
Expected dividend yield	2.4%	2.9% – 3.1%
Weighted-average expected dividend yield	2.4%	3.1%
Expected volatility	16.2%	18.7% – 19.6%
Weighted-average volatility	16.2%	19.6%


			Weighted-Average
	Stock Options		Exercise Price		Remaining Contractual Term (Years)	Aggregate Intrinsic Value
	(Unaudited)
Outstanding at Dec. 31, 2005	15,331,659		$	22.99
Granted	1,905,406		$	44.30
Expired	—			—
Forfeited	(24,041	)	$	29.39
Exercised	(986,087	)	$	20.74
Outstanding at March 31, 2006	16,226,937		$	25.61
Vested and expected to vest at March 31, 2006	15,549,019		$	25.41	6.75	$	277,239,008
Exercisable at March 31, 2006	8,595,410		$	21.91	5.43	$	183,340,095


			Weighted-Average
	Performance Shares		Grant-Date Fair Value
	(Unaudited)
Nonvested at Dec. 31, 2005	280,289		$	39.19
Granted	81,469		$	53.24
Forfeited	(1,499	)	$	40.33
Nonvested at March 31, 2006	360,259		$	42.36


	Performance Shares		Weighted-Average Fair Value
	(Unaudited)
Nonvested at Dec. 31, 2005	280,434
Granted	81,555
Forfeited	(1,501	)
Nonvested at March 31, 2006	360,488		$	92.08


In millions	Tax Years Under Appeal 1994 – 1999		Unaudited Tax Years 2000 – 2005		Total
Replacement Leases (SILO)	$	44	$	36	$	80
Lease/Leaseback (LILO)		558		570		1,128
Service Contract (SILO)		—		272		272
	$	602	$	878	$	1,480


		Page
Current Developments		34
Southern California Edison Company		36
Edison Mission Group Inc.		41
Edison International (Parent)		57
Results of Operations and Historical Cash Flow Analysis		59
Acquisitions and Dispositions		66
New Accounting Pronouncements		66
Commitments, Guarantees and Indemnities		67
Other Developments		67


	March 31, 2006				December 31, 2005
In millions	Assets		Liabilities		Assets		Liabilities
Energy options and tolling arrangements	$	—	$	20	$	25	$	—
Forward physicals (power)		—		105		—		49
Gas options, swaps, and forward arrangements		—		110		105		—
Total	$	—	$	235	$	130	$	49


	Moody’s Rating	S&P Rating
MEHC	B2	CCC+
EME	B1	B+
Midwest Generation:
First priority senior secured rating	Ba3	BB-
Second priority senior secured rating	B1	B
EMMT	Not Rated	B+


In millions	Three Months Ended March 31,	2006		2005
Distributions from Consolidated Operating Projects:
Edison Mission Midwest Holdings (Illinois plants)⁽¹⁾		$	185	$	62
EME Homer City Generation L.P. (Homer City facilities)			—		24

Distributions from Unconsolidated Operating Projects:
Edison Mission Energy Funding Corp. (Big 4 Projects)⁽²⁾			40		29
Holding companies for Westside projects			2		3
Holding companies of other unconsolidated operating projects			—		3
Total Distributions		$	227	$	121
(1) Subsequent to March 31, 2006, Edison Mission Midwest Holdings made an additional distribution of $196 million. (2) The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project, Sycamore project and Watson project. Distributions reflect the amount received by EME after debt service payments by Edison Mission Energy Funding Corp.


Subsidiary	Financial Ratio	Covenant	Actual
MEHC	Interest Coverage Ratio	Greater than 2.0 to 1	2.83 to 1
Midwest Generation, LLC (Illinois plants)	Interest Coverage Ratio	Greater than or equal to 1.40 to 1	6.58 to 1
Midwest Generation, LLC (Illinois plants)	Secured Leverage Ratio	Less than or equal to 7.25 to 1	1.75 to 1
EME Homer City Generation L.P. (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.37 to 1⁽¹⁾


	24-Hour Northern Illinois Hub Historical Energy Prices*
	2006		2005
January	$	42.27	$	38.36
February		42.66		34.92
March		42.50		45.75
Quarterly Average	$	42.48	$	39.68


	24-Hour Northern Illinois Hub Forward Energy Prices*
2006
April	$	40.42
May		40.21
June		43.94
July		52.82
August		54.92
September		43.06
October		40.28
November		42.61
December		52.26

2007 Calendar “strip”⁽¹⁾	$	48.61


	2006	2007
Megawatt hours	13,166,940	15,030,000
Average price/MWh⁽¹⁾	$ 47.60	$ 49.22


	Historical Energy Prices* 24-Hour PJM
	Homer City				West Hub
	2006		2005		2006		2005
January	$	48.67	$	45.82	$	54.57	$	49.53
February		49.54		39.40		56.39		42.05
March		53.26		47.42		58.30		49.97
Quarterly Average	$	50.49	$	44.21	$	56.42	$	47.18


	24-Hour PJM West Hub Forward Energy Prices*
2006
April	$	51.67
May		51.99
June		57.21
July		68.87
August		70.85
September		56.44
October		54.40
November		57.26
December		66.63
2007 Calendar “strip”(1)	$	66.79


	Percent of Coal Requirements Under Contract
	2006⁽¹⁾		2007		2008		2009		2010
Illinois plants	104	%	95	%	33	%	33	%	33	%
Homer City facilities	102	%	90	%	36	%	15	%	0	%


In millions	March 31, 2006
S&P Credit Rating
A or higher	$	54
A-		58
BBB+		51
BBB		62
BBB-		1
Below investment grade		5
Total	$	231


In millions	Total Fair Value	Maturity Less than 1 year	Maturity 1 to 3 years	Maturity 4 to 5 years	Maturity Greater than 5 years
Prices actively quoted	$ (165)	$ (139)	$ (26)	$ —	$ —


In millions
Fair value of trading contracts at January 1, 2006	$	101
Net gains from energy trading activities		32
Amount realized from energy trading activities		(22	)
Other changes in fair value		(1	)
Fair value of trading contracts at March 31, 2006	$	110


In millions, except per common share amounts	Earnings (Loss)						Earnings (Loss) per Common Share
Three-Month Period Ended March 31,	2006			2005			2006			2005
Earnings (Loss) from Continuing Operations:
SCE	$	121		$	131		$	0.37		$	0.40
EMG:
MEHC		56			25			0.18			0.08
Edison Capital and other		17			51			0.05			0.16
EMG Total		73			76			0.23			0.24
Edison International (parent) and other		(10	)		(13	)		(0.04	)		(0.05	)
Edison International Consolidated Earnings from Continuing Operations		184			194			0.56			0.59
Earnings from Discontinued Operations		73			7			0.22			0.02
Cumulative Effect of Change in Accounting Principle		1			—			—			—
Edison International Consolidated	$	258		$	201		$	0.78		$	0.61


In millions	Three-Month Period Ended March 31,	2006 vs. 2005
Electric utility revenue
Rate changes (including unbilled)		$	156
Sales volume changes (including unbilled)			20
Deferred revenue			185
Sales for resale			(89	)
SCE’s variable interest entities			16
Other (including intercompany transactions)			21
Total		$	309


In millions	Tax Years Under Appeal 1994 – 1999		Unaudited Tax Years 2000 – 2005		Total
Replacement Leases (SILO)	$	44	$	36	$	80
Lease/Leaseback (LILO)		558		570		1,128
Service Contract (SILO)		—		272		272
	$	602	$	878	$	1,480


Period	(a) Total Number of Shares (or Units) Purchased¹	(b) Average Price Paid per Share (or Unit)¹		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 1, 2006 to January 31, 2006	1,913,921	$	44.70	—	—

February 1, 2006 to February 28, 2006	426,216	$	43.91	—	—

March 1, 2006 to March 31, 2006	941,979	$	42.77	—	—
Total	3,282,116	$	44.04	—	—


10.1		Letter agreement between Robert G. Foster and Southern California Edison Company, dated April 25, 2006

10.2		Terms and conditions for 2006 long-term compensation awards under the Equity Compensation Plan and 2000 Equity Plan (File No. 1-9936, filed as Exhibit 10.29 to Edison International’s Form 10-K for the year ended December 31, 2005)*

10.3		Edison International Named Executive Officer Base Salaries for 2006 (File No. 1-9936, filed as Exhibit 10.57 to Edison International’s Form 10-K for the year ended December 31, 2005)*

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

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

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