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UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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Form 10-Q

|(Mark one)
|----------
|ý         

For the Quarterly Period Ended March 31, 2003

or

|o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|- | ----------------------------------------------------------------------------------------
|  | For the transition period from 
to                                                      

Commission file number 000-24890

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EDISON MISSION ENERGY(Exact name of registrant as specified in its charter)

Delaware

95-4031807(State or other jurisdiction of
incorporation or organization)

(I.R.S. Employer Identification No.)18101 Von Karman Avenue
Irvine, California(Address of principal executive offices)

92612(Zip Code)


Registrant's telephone number, including area code:(949) 752-5588

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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 ý NO o

Indicate
by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the
Act). YES o NO ý

Number
of shares outstanding of the registrant's Common Stock as of May 14, 2003: 100 shares (all shares held by an affiliate of the registrant).

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TABLE OF CONTENTS

|        |  |                                                                                       |  | Page
|------- |  | ------------------------------------------------------------------------------------- |  | ----
|        |  | PART IFinancial Information                                                          |  |     
|Item 1. |  | Financial Statements                                                                  |  | 1   
|Item 2. |  | Management's Discussion and Analysis of Results of Operations and Financial Condition |  | 19  
|Item 3. |  | Quantitative and Qualitative Disclosures about Market Risk                            |  | 58  
|Item 4. |  | Controls and Procedures                                                               |  | 58  
|        |  | PART IIOther Information                                                             |  |     
|Item 6. |  | Exhibits and Reports on Form 8-K                                                      |  | 60  
|        |  | Signatures                                                                            |  | 61  
|        |  | Certifications                                                                        |  | 62  

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PART IFINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF OPERATIONS        (In thousands)

|                                |                                                                                  | Three Months Ended
March 31, |        
|------------------------------- | -------------------------------------------------------------------------------- | ---------------------------- | -------
|
|
|Operating Revenues              |                                                                                  |                              |        
|                                | Electric revenues                                                                |                              | $      
|                                | Net gains (losses) from price risk management and energy trading                 |                              |        
|                                | Operation and maintenance services                                               |                              |        
|                                |                                                                                  |                              |        
|                                |                                                                                  | Total operating revenues     |        
|                                |                                                                                  |                              |        
|Operating Expenses              |                                                                                  |                              |        
|                                | Fuel                                                                             |                              |        
|                                | Plant operations and transmission costs                                          |                              |        
|                                | Plant operating leases                                                           |                              |        
|                                | Operation and maintenance services                                               |                              |        
|                                | Depreciation and amortization                                                    |                              |        
|                                | Administrative and general                                                       |                              |        
|                                |                                                                                  |                              |        
|                                |                                                                                  | Total operating expenses     |        
|                                |                                                                                  |                              |        
|                                | Operating income (loss)                                                          |                              |        
|                                |                                                                                  |                              |        
|Other Income (Expense)          |                                                                                  |                              |        
|                                | Equity in income from unconsolidated affiliates                                  |                              |        
|                                | Interest and other income                                                        |                              |        
|                                | Interest expense                                                                 |                              |        
|                                | Dividends on preferred securities                                                |                              |        
|                                |                                                                                  |                              |        
|                                |                                                                                  | Total other income (expense) |        
|                                |                                                                                  |                              |        
|                                | Loss from continuing operations before income taxes and minority interest        |                              |        
|                                | Benefit for income taxes                                                         |                              |        
|                                | Minority interest                                                                |                              |        
|                                |                                                                                  |                              |        
|Loss From Continuing Operations |                                                                                  |                              | (8,481 
|                                | Income from operations of discontinued foreign subsidiaries, net of tax (Note 6) |                              |        
|                                |                                                                                  |                              |        
|Loss Before Accounting Change   |                                                                                  |                              | (8,253 
|                                | Cumulative effect of change in accounting, net of tax (Notes 3 and 12)           |                              |        
|                                |                                                                                  |                              |        
|Net Loss                        |                                                                                  | $                            | (16,824
|                                |                                                                                  |                              |        

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

1

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EDISON MISSION ENERGY AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)        (In thousands)

|                                        |                                                                         | Three Months Ended
March 31,                                                                                                                                                                 |        
|--------------------------------------- | ----------------------------------------------------------------------- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | -------
|
|
|Net Loss                                |                                                                         | $                                                                                                                                                                                            | (16,824
|Other comprehensive income, net of tax: |                                                                         |                                                                                                                                                                                              |        
|                                        | Foreign currency translation adjustments:                               |                                                                                                                                                                                              |        
|                                        |                                                                         | Foreign currency translation adjustments, net of income tax expense of $965 and $867 for the three months ended March 31, 2003 and 2002, respectively                                        |        
|                                        | Minimum pension liability adjustment                                    |                                                                                                                                                                                              |        
|                                        | Unrealized gains (losses) on derivatives qualified as cash flow hedges: |                                                                                                                                                                                              |        
|                                        |                                                                         | Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(17,596) and $11,457 for the three months ended March 31, 2003 and 2002, respectively |        
|                                        |                                                                         | Reclassification adjustments included in net loss, net of income tax expense (benefit) of $(3,932) and $428 for the three months ended March 31, 2003 and 2002, respectively                 |        
|                                        |                                                                         |                                                                                                                                                                                              |        
|Other comprehensive income              |                                                                         |                                                                                                                                                                                              | 17,073 
|                                        |                                                                         |                                                                                                                                                                                              |        
|Comprehensive Income                    |                                                                         | $                                                                                                                                                                                            | 249    
|                                        |                                                                         |                                                                                                                                                                                              |        

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

2

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EDISON MISSION ENERGY AND SUBSIDIARIES        CONSOLIDATED BALANCE SHEETS        (In thousands)

|                                         |                                                                                                   | March 31,
2003                    |            | December 31,
2002
|---------------------------------------- | ------------------------------------------------------------------------------------------------- | --------------------------------- | ---------- | -----------------
|
|Assets                                   |                                                                                                   |                                   |            |                  
|Current Assets                           |                                                                                                   |                                   |            |                  
|                                         | Cash and cash equivalents                                                                         |                                   | $          | 653,651          
|                                         | Accounts receivabletrade, net of allowance of $12,316 and $13,113 in 2003 and 2002, respectively |                                   |            | 379,677          
|                                         | Accounts receivableaffiliates                                                                    |                                   |            | 32,103           
|                                         | Assets under price risk management and energy trading                                             |                                   |            | 48,126           
|                                         | Inventory                                                                                         |                                   |            | 159,443          
|                                         | Prepaid expenses and other                                                                        |                                   |            | 149,680          
|                                         |                                                                                                   |                                   |            |                  
|                                         |                                                                                                   | Total current assets              |            |                  
|                                         |                                                                                                   |                                   |            |                  
|Investments in Unconsolidated Affiliates |                                                                                                   |                                   | 1,681,093  |                  
|                                         |                                                                                                   |                                   |            |                  
|Property, Plant and Equipment            |                                                                                                   |                                   | 8,077,943  |                  
|                                         | Less accumulated depreciation and amortization                                                    |                                   |            | 979,015          
|                                         |                                                                                                   |                                   |            |                  
|                                         |                                                                                                   | Net property, plant and equipment |            |                  
|                                         |                                                                                                   |                                   |            |                  
|Other Assets                             |                                                                                                   |                                   |            |                  
|                                         | Goodwill                                                                                          |                                   |            | 734,676          
|                                         | Deferred financing costs                                                                          |                                   |            | 52,081           
|                                         | Long-term assets under price risk management and energy trading                                   |                                   |            | 121,615          
|                                         | Restricted cash and other                                                                         |                                   |            | 506,237          
|                                         |                                                                                                   |                                   |            |                  
|                                         |                                                                                                   | Total other assets                |            |                  
|                                         |                                                                                                   |                                   |            |                  
|Assets of Discontinued Operations        |                                                                                                   |                                   | 5,795      |                  
|                                         |                                                                                                   |                                   |            |                  
|Total Assets                             |                                                                                                   | $                                 | 11,623,105 |                  
|                                         |                                                                                                   |                                   |            |                  

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

3

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EDISON MISSION ENERGY AND SUBSIDIARIES        CONSOLIDATED BALANCE SHEETS        (In thousands)

|                                                |                                                                                                      | March 31,
2003                             |            | December 31,
2002 |          
|----------------------------------------------- | ---------------------------------------------------------------------------------------------------- | ------------------------------------------ | ---------- | ----------------- | ---------
|
|Liabilities and Shareholder's Equity            |                                                                                                      |                                            |            |                   |          
|Current Liabilities                             |                                                                                                      |                                            |            |                   |          
|                                                | Accounts payableaffiliates                                                                          |                                            | $          | 21,653            |          
|                                                | Accounts payable and accrued liabilities                                                             |                                            |            | 465,708           |          
|                                                | Liabilities under price risk management and energy trading                                           |                                            |            | 134,135           |          
|                                                | Interest payable                                                                                     |                                            |            | 89,891            |          
|                                                | Short-term obligations                                                                               |                                            |            | 126,916           |          
|                                                | Current maturities of long-term obligations                                                          |                                            |            | 1,204,988         |          
|                                                |                                                                                                      |                                            |            |                   |          
|                                                |                                                                                                      | Total current liabilities                  |            |                   | 2,043,291
|                                                |                                                                                                      |                                            |            |                   |          
|Long-Term Obligations Net of Current Maturities |                                                                                                      |                                            | 5,104,912  |                   |          
|                                                |                                                                                                      |                                            |            |                   |          
|Long-Term Deferred Liabilities                  |                                                                                                      |                                            |            |                   |          
|                                                | Deferred taxes and tax credits                                                                       |                                            |            | 1,200,775         |          
|                                                | Deferred revenue                                                                                     |                                            |            | 479,978           |          
|                                                | Long-term incentive compensation                                                                     |                                            |            | 29,036            |          
|                                                | Long-term liabilities under price risk management and energy trading                                 |                                            |            | 136,855           |          
|                                                | Other                                                                                                |                                            |            | 206,117           |          
|                                                |                                                                                                      |                                            |            |                   |          
|                                                |                                                                                                      | Total long-term deferred liabilities       |            |                   | 2,052,761
|                                                |                                                                                                      |                                            |            |                   |          
|Liabilities of Discontinued Operations          |                                                                                                      |                                            | 2,723      |                   |          
|                                                |                                                                                                      |                                            |            |                   |          
|Total Liabilities                               |                                                                                                      |                                            | 9,203,687  |                   |          
|                                                |                                                                                                      |                                            |            |                   |          
|Minority Interest                               |                                                                                                      |                                            | 437,722    |                   |          
|                                                |                                                                                                      |                                            |            |                   |          
|Preferred Securities of Subsidiaries            |                                                                                                      |                                            |            |                   |          
|                                                | Company-obligated mandatorily redeemable security of partnership holding solely parent debentures    |                                            |            | 150,000           |          
|                                                | Subject to mandatory redemption                                                                      |                                            |            | 138,425           |          
|                                                |                                                                                                      |                                            |            |                   |          
|                                                |                                                                                                      | Total preferred securities of subsidiaries |            |                   | 288,425  
|                                                |                                                                                                      |                                            |            |                   |          
|Commitments and Contingencies (Note 7)          |                                                                                                      |                                            |            |                   |          
|Shareholder's Equity                            |                                                                                                      |                                            |            |                   |          
|                                                | Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding |                                            |            | 64,130            |          
|                                                | Additional paid-in capital                                                                           |                                            |            | 2,632,917         |          
|                                                | Retained deficit                                                                                     |                                            |            | (808,628          | )        
|                                                | Accumulated other comprehensive loss                                                                 |                                            |            | (195,148          | )        
|                                                |                                                                                                      |                                            |            |                   |          
|Total Shareholder's Equity                      |                                                                                                      |                                            | 1,693,271  |                   |          
|                                                |                                                                                                      |                                            |            |                   |          
|Total Liabilities and Shareholder's Equity      |                                                                                                      | $                                          | 11,623,105 |                   | $        
|                                                |                                                                                                      |                                            |            |                   |          

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

4

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EDISON MISSION ENERGY AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF CASH FLOWS        (In thousands)

|                                                                        |                                                                                         | Three Months Ended
March 31,                                    |         
|----------------------------------------------------------------------- | --------------------------------------------------------------------------------------- | --------------------------------------------------------------- | --------
|
|
|Cash Flows From Operating Activities                                    |                                                                                         |                                                                 |         
|                                                                        | Loss from continuing operations, after accounting change, net                           |                                                                 | $       
|                                                                        | Adjustments to reconcile income to net cash provided by (used in) operating activities: |                                                                 |         
|                                                                        |                                                                                         | Equity in income from unconsolidated affiliates                 |         
|                                                                        |                                                                                         | Distributions from unconsolidated affiliates                    |         
|                                                                        |                                                                                         | Depreciation and amortization                                   |         
|                                                                        |                                                                                         | Deferred taxes and tax credits                                  |         
|                                                                        |                                                                                         | Cumulative effect of change in accounting, net of tax           |         
|                                                                        | Changes in operating assets and liabilities:                                            |                                                                 |         
|                                                                        |                                                                                         | Decrease (increase) in accounts receivable                      |         
|                                                                        |                                                                                         | Decrease (increase) in inventory                                |         
|                                                                        |                                                                                         | Decrease in prepaid expenses and other                          |         
|                                                                        |                                                                                         | Increase (decrease) in accounts payable and accrued liabilities |         
|                                                                        |                                                                                         | Decrease in interest payable                                    |         
|                                                                        |                                                                                         | Increase in long-term incentive compensation                    |         
|                                                                        |                                                                                         | Decrease (increase) in net assets under risk management         |         
|                                                                        | Other operating, net                                                                    |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 | (1,961  
|                                                                        | Operating cash flow from discontinued operations                                        |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         | Net cash provided by (used in) operating activities             |         
|                                                                        |                                                                                         |                                                                 |         
|Cash Flows From Financing Activities                                    |                                                                                         |                                                                 |         
|                                                                        | Borrowings on long-term debt and lease swap agreements                                  |                                                                 |         
|                                                                        | Payments on long-term debt agreements                                                   |                                                                 |         
|                                                                        | Short-term financing and lease swap agreements, net                                     |                                                                 |         
|                                                                        | Financing costs                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 | 323,219 
|                                                                        | Financing cash flow from discontinued operations                                        |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         | Net cash provided by (used in) financing activities             |         
|                                                                        |                                                                                         |                                                                 |         
|Cash Flows From Investing Activities                                    |                                                                                         |                                                                 |         
|                                                                        | Investments in and loans to energy projects                                             |                                                                 |         
|                                                                        | Purchase of common stock of acquired companies                                          |                                                                 |         
|                                                                        | Purchase of power sales agreement                                                       |                                                                 |         
|                                                                        | Capital expenditures                                                                    |                                                                 |         
|                                                                        | Proceeds from return of capital and loan repayments                                     |                                                                 |         
|                                                                        | Proceeds from sale of interest in projects                                              |                                                                 |         
|                                                                        | Decrease in restricted cash                                                             |                                                                 |         
|                                                                        | Investments in other assets                                                             |                                                                 |         
|                                                                        | Other, net                                                                              |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 | (328,444
|                                                                        | Investing cash flow from discontinued operations                                        |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         | Net cash used in investing activities                           |         
|                                                                        |                                                                                         |                                                                 |         
|Effect of exchange rate changes on cash                                 |                                                                                         |                                                                 | 9,268   
|                                                                        |                                                                                         |                                                                 |         
|Net increase (decrease) in cash and cash equivalents                    |                                                                                         |                                                                 | 6,536   
|Cash and cash equivalents at beginning of period                        |                                                                                         |                                                                 | 647,240 
|                                                                        |                                                                                         |                                                                 |         
|Cash and cash equivalents at end of period                              |                                                                                         |                                                                 | 653,776 
|Cash and cash equivalents classified as part of discontinued operations |                                                                                         |                                                                 | (125    
|                                                                        |                                                                                         |                                                                 |         
|Cash and cash equivalents of continuing operations                      |                                                                                         | $                                                               | 653,651 
|                                                                        |                                                                                         |                                                                 |         

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

5

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EDISON MISSION ENERGY AND SUBSIDIARIES        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        MARCH 31, 2003        (Dollars in millions)

Note 1. General

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to present fairly the consolidated financial
position and results of operations for the periods covered by this report. The results of operations for the three months ended March 31, 2003 are not necessarily indicative of the operating
results for the full year.

Edison
Mission Energy's (EME's) significant accounting policies are described in Note 2 to its Consolidated Financial Statements as of December 31, 2002 and 2001, included
in EME's annual report on Form 10-K for the year ended December 31, 2002. EME follows the same accounting policies for interim reporting purposes. This quarterly report
should be read in connection with such financial statements.

Terms
used but not defined in this report are defined in EME's annual report on Form 10-K for the year ended December 31, 2002. Certain prior period amounts
have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on net income or shareholder's equity.

Current Developments

A number of significant developments during late 2001 and 2002 adversely affected independent power producers and subsidiaries of major integrated energy
companies that sell a sizable portion of their generation into the wholesale energy market (sometimes referred to as merchant generators), including several of EME's subsidiaries. These developments
included lower market prices in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of most major market participants, decreased
availability of debt financing or refinancing, and a resulting decline of liquidity in the energy markets due to growing concern about the ability of counterparties to perform their obligations. Since
the beginning of 2003, several merchant generators reached agreements to extend existing bank credit facilities.

EME's
largest subsidiary, Edison Mission Midwest Holdings, has $911 million of debt maturing in December 2003 which will need to be repaid, extended or refinanced. Edison
Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due in December 2003, and there is no assurance that Edison Mission Midwest Holdings will
be able to extend or refinance its debt obligation on similar terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into
by EME's parent company, Mission Energy Holding Company, in July 2001, or at all. EME's independent accountants' audit opinion for the year ended December 31, 2002 contains an
explanatory paragraph that indicates the consolidated financial statements have been prepared on the basis that EME will continue as a going concern and that the uncertainty about Edison Mission
Midwest Holdings' ability to repay, extend or refinance this obligation raises substantial doubt about EME's ability to continue as a going concern. Accordingly, the consolidated financial statements
do not include any adjustments that might result from the resolution of this uncertainty.

During
the first quarter of 2003, wholesale energy prices in the Pennsylvania-New Jersey-Maryland Power Pool, or PJM, increased primarily due to
colder-than-normal weather and increases in the prices for natural gas. However, the recent changes in wholesale energy prices may or may not continue

6

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throughout
2003. See "Item 2. Management's Discussion and Analysis of Results of Operations and Financial ConditionMarket Risk Exposures" for more information regarding forward
market prices.

Note 2. Acquisitions and Dispositions

Acquisitions

On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to acquire the Taranaki Combined Cycle
power station and related interests. The Taranaki station is a 357 MW combined cycle, natural gas-fired plant located near Stratford, New Zealand. Consideration for the Taranaki
station consisted of a cash payment of approximately $275 million, which was financed with bridge loan facilities. The bridge loan facilities were subsequently repaid with proceeds from the
issuance of long-term U.S. dollar denominated notes.

Dispositions

During the first quarter of 2002, EME completed the sales of its 50% interests in the Commonwealth Atlantic and James River projects and its 30% interest in the
Harbor project. Proceeds received from the sales were $44 million. During 2001, EME recorded asset impairment charges of $32 million related to these projects based on the expected sales
proceeds. No gain or loss was recorded from the sale of EME's interests in these projects during the first quarter of 2002.

Note 3. Goodwill and Intangible Assets

Effective January 1, 2002, EME adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS
No. 142 establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. EME will perform
its annual evaluation of goodwill on October 1, 2003 or sooner if indicators of impairment exist. During the third quarter of 2002, EME concluded that fair value of the goodwill related to the
Citizens Power LLC acquisition was impaired by $14 million, net of $9 million of income tax benefit and, accordingly, reported this amount as a cumulative change in accounting. In
accordance with SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements," EME's financial statements for the first quarter of 2002 were restated to reflect the accounting
change as of January 1, 2002.

Included
in "Restricted cash and other assets" on EME's consolidated balance sheet are customer contracts with a gross carrying amount of $87 million and accumulated amortization
of $6 million at March 31, 2003. The contracts have a weighted average amortization period of 20 years. For the three months ended March 31, 2003, the amortization expense
was $1 million. Based on the current amount of intangible assets subject to amortization, the estimated amortization expense for fiscal years 2004 through 2008 is $5 million each year.
Intangible assets classified in "Restricted cash and other assets" of $1 million at March 31, 2003 consists of an additional minimum pension liability at Midwest Generation.

7

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Changes
in the carrying amount of goodwill, by geographical segment, for the three months ended March 31, 2003 are as follows:

|                                              |  | Americas |   | Asia Pacific |   | Europe |  | Total
|--------------------------------------------- |  | -------- | - | ------------ | - | ------ |  | -----
|Carrying amount at December 31, 2002          |  | $        | 2 |              | $ | 384    |  | $    
|Goodwill resulting from an acquisition(1)     |  |          |  |              |   | 43     |  |      
|Translation adjustments and other             |  |          |  |              |   | 37     |  |      
|                                              |  |          |   |              |   |        |  |      
|Carrying amount at March 31, 2003 (unaudited) |  | $        | 2 |              | $ | 464    |  | $    
|                                              |  |          |   |              |   |        |  |      

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Note 4. Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory at March 31, 2003 and December 31, 2002 consisted of the following:

March 31,
2003

December 31,
2002(Unaudited)Coal and fuel oil

$
92

$
111Spare parts, materials and supplies


67


65Total

$
159

$
176


Note 5. Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) consisted of the following:

|                                      |  | Currency
Translation
Adjustments |    | Unrealized Gains
(Losses) on Cash
Flow Hedges |   | Minimum
Pension Liability
Adjustment |   | Accumulated Other
Comprehensive
Income (Loss) |    
|------------------------------------- |  | -------------------------------- | -- | --------------------------------------------- | - | ------------------------------------ | - | --------------------------------------------- | ---
|Balance at December 31, 2002          |  | $                                | (8 | )                                             | $ | (193                                 | ) | $                                             | (11
|Current period change                 |  |                                  | 21 |                                               |   | (4                                   | ) |                                               |   
|                                      |  |                                  |    |                                               |   |                                      |   |                                               |    
|Balance at March 31, 2003 (unaudited) |  | $                                | 13 |                                               | $ | (197                                 | ) | $                                             | (11
|                                      |  |                                  |    |                                               |   |                                      |   |                                               |    

Unrealized
gains (losses) on cash flow hedges included those related to the hedge agreement with the State Electricity Commission of Victoria for electricity prices from the Loy Yang B
project in Australia. This contract does not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. These losses arise
because current forecasts of future electricity prices in these markets are greater than contract prices. In addition to this contract, unrealized gains (losses) on cash flow hedges included those
related to EME's share of interest rate swaps of its unconsolidated affiliates and the Loy Yang B project.

As
EME's hedged positions are realized, approximately $10 million, after tax, of the net unrealized losses on cash flow hedges at March 31, 2003 are expected to be
reclassified into earnings during the next 12 months. Management expects that when the hedged items are recognized in earnings, the net unrealized losses associated with them will be offset.
The maximum period over which EME has designated a cash flow hedge, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is
14 years. 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.

8

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Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective
portion, is immediately recognized in earnings. EME recorded a net loss of approximately $8 million and $1 million during the first quarters of 2003 and 2002, respectively, representing
the amount of cash flow hedges' ineffectiveness, reflected in net gains (losses) from price risk management and energy trading in EME's consolidated income statement.

Note 6. Discontinued Operations

Lakeland Project

EME's Lakeland project operated a 220 MW combined cycle, natural gas-fired power plant located in the United Kingdom. The assets of the project
are owned by EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU
(UK) Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe).

On
December 19, 2002, the lenders to the Lakeland project accelerated the debt owing under the bank agreement that governs the project's indebtedness, and on December 20,
2002, the Lakeland project lenders appointed an administrative receiver over the assets of Lakeland Power Ltd. The administrative receiver was appointed to take control of the affairs of
Lakeland Power Ltd. and has a wide range of powers (specified in the Insolvency Act), including authorizing the sale of the power plant. The appointment of the administrative receiver requires
the treatment of Lakeland power plant as an asset held for sale under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets" (SFAS No. 144). Due to EME's loss of control arising from the appointment of the administrative receiver, EME no longer consolidates the activities of Lakeland Power Ltd. The
consolidated financial statements have been restated to conform to discontinued operations treatment for all historical periods presented.

On
April 22, 2003, a third party announced that it had entered an agreement with the administrative receiver to purchase the Lakeland power plant for
£24 million. Subject to satisfaction of closing conditions, completion of the sale is expected during the second quarter of 2003.

Ferrybridge and Fiddler's Ferry Plants

On December 21, 2001, EME completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to
two wholly owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants.
The sale was the result of a competitive bidding process. EME acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. In accordance with SFAS No. 144, the results
of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in EME's consolidated financial statements. The consolidated financial statements have been restated to conform to
discontinued operations treatment for all historical periods presented.

Summarized
results of discontinued operations are as follows:

Three Months Ended
March 31,2003

2002(Unaudited)Total operating revenues

$


$
21Income before income taxes





5Income from operations of discontinued foreign subsidiaries





5


9

---

The
following summarizes the balance sheet information of the discontinued operations:

March 31,
2003

December 31, 2002(Unaudited)Accounts receivabletrade, net of allowance of $2 million in 2003 and 2002

$
3

$
1Other current assets


2


3Total current assets


5


4Other long-term assets


1


6Assets of discontinued operations

$
6

$
10Accounts payable and accrued liabilities

$
3

$
3Total current liabilities


3


3Liabilities of discontinued operations

$
3

$
3


Note 7. Commitments and Contingencies

Commercial Commitments

The following table summarizes EME's consolidated commercial commitments as of March 31, 2003. Details regarding these commercial commitments are discussed
in the sections following the table.

|                                                   |  | Amount of Commitments Per Period in U.S.$ |     | 
|-------------------------------------------------- |  | ----------------------------------------- | --- | 
|
|
|Standby letters of credit                          |  | $                                         | 121 | 
|Firm commitments to contribute project equity      |  |                                           | 47  | 
|Capital improvements at EME's project subsidiaries |  |                                           | 15  | 
|                                                   |  |                                           |     | 
|Total Commercial Commitments                       |  | $                                         | 183 | 
|                                                   |  |                                           |     | 

Firm Commitments to Contribute Project Equity

Projects

U.S. CurrencyCBK(i)

$
30Sunrise(ii)

$
17


---

10

---



Firm
commitments to contribute project equity to the CBK project could be accelerated due to events of default as defined in the non-recourse project financing facilities.

Contingencies



Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources under an
eleven-year power purchase agreement entered into on June 25, 2001 and restructured on December 31, 2002. In January 2003, the California Public Utilities Commission
and the California Electricity Oversight Board dismissed the complaints they had filed with the Federal Energy Regulatory Commission against Sunrise Power Company, alleging that the contract was
"unjust and unreasonable."

On
May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Superior Court of the State of California, Los Angeles County, against the
California Department of Water Resources, all sellers of power under long-term energy contracts entered into in 2001, including Sunrise Power Company, and Vikram Budhraja, one of the
consultants involved in the negotiation of energy contracts on behalf of the California Department of Water Resources. The lawsuit asks the Superior Court to void all the contracts entered into in
2001, as well as all the contracts renegotiated in 2002, as a result of a purported conflict of interest by Mr. Budhraja. Sunrise Power Company has not yet been served with the complaint.

On
May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar,
"individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including
Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated
power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of
excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with
those lawsuits. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California, and filed a motion to stay all
proceedings pending final resolution of the jurisdictional issue. Various plaintiffs have filed pleadings opposing the removal and requesting that the matters be remanded to state court. The motions
are still pending. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.



On August 4, 2002, a new Electricity Market License Regulation was implemented in Turkey. The regulation contains, among other things, a requirement for
each generator to obtain a generation license. Historically, Doga's Implementation Contract has been its sole license. The new regulation contemplates an initial fixed license fee and a yearly license
fee based on the amount of energy generated, which will increase the project's costs of operation by an undetermined amount. In addition, the regulation allows the insertion of provisions in the
license which are different from those in the Implementation Contract.

11

---

The
effect of the new regulation is still undetermined, as the new license provisions have not been specified. The new regulation requires Doga to apply for a generation license by
June 2, 2003. If actions or inactions undertaken pursuant to the new regulation directly or indirectly impede, hinder, prevent or delay the operation of the Doga facility or increase Doga's
cost of performing its obligations under its project documents, this may constitute a risk event under Doga's Implementation Contract. A risk event may permit Doga to request an increase in its tariff
or, under certain circumstances, request a buyout of the project by the Ministry of Energy and Natural Resources.

On
October 3, 2002, Doga and several other independent power producers filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy Market Regulatory
Authority seeking invalidation of certain provisions of the new regulation, arguing the unconstitutionality of the
imposition of new license requirements that do not take into account the vested rights of companies presently performing electricity generation pursuant to previously agreed conditions. No decision
has been rendered, and discussions with the Turkish authorities continue.



EME is, and may in the future be, under examination by tax authorities in varying tax jurisdictions with respect to positions it takes in connection with the
filing of its tax returns. Matters raised upon audit may involve substantial amounts, which, if resolved unfavorably, an event not currently anticipated, could possibly be material. However, in EME's
opinion, it is unlikely that the resolution of any such matters will have a material adverse effect upon EME's financial condition or results of operations.

Litigation

EME experiences other routine litigation in the normal course of its business. None of such pending routine litigation is expected to have a material adverse
effect on EME's consolidated financial position or results of operations.

Guarantees and Indemnities



In connection with the sale-leaseback transactions that EME has entered into related to the Collins Station, Powerton and Joliet plants in Illinois
and the Homer City facilities in Pennsylvania, EME or one of its subsidiaries has entered into tax indemnity agreements. Under these tax indemnity agreements, EME has 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 obligations under these tax indemnity agreements,
EME cannot determine a maximum potential liability. The indemnities would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities.



In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison against damages, claims, fines, liabilities and expenses
and losses arising from, among other things, environmental liabilities before and after the date of sale as specified in the Asset Sale Agreement dated March 22, 1999. The indemnification
claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement by Commonwealth Edison to take 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. The indemnification for the environmental liabilities
referred to above is not limited in term and would be

12

---

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 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 50% of specific existing
asbestos claims less recovery of insurance costs, and agreed to a sharing arrangement for liabilities associated with future asbestos related claims as specified in the agreement. 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 to terminate).
Payments are made under this indemnity by a valid claim provided from Commonwealth Edison. At March 31, 2003, Midwest Generation recorded a $5 million liability related to known claims
provided by Commonwealth Edison.



In connection with the acquisition of the Homer City facilities, EME Homer City Generation L.P. is obligated to indemnify the sellers against damages, claims and
losses arising from environmental liabilities before and after the date of sale as specified in the Asset Purchase Agreement dated August 1, 1998. 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 nor has 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.



In connection with the sale of assets, EME has provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale,
and EME or its subsidiaries have received similar indemnities from purchasers related to taxes arising from operations after 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.



Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. EME's wholly owned subsidiary owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. A settlement agreement was
executed on January 17, 2003, and all litigation has been dismissed. EME has indemnified Brooklyn Navy Yard Cogeneration Partners, L.P. for any payments due under this settlement agreement
which are scheduled through 2006. At March 31, 2003, EME recorded a liability of $12 million related to this indemnity.



TM Star was formed for the limited purpose of selling natural gas to March Point Cogeneration Company, an affiliate through common ownership, under a fuel supply
agreement that extends through December 31, 2011. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of the obligations under the fuel supply
agreement. EME has guaranteed 50% of TM Star's obligation under the fuel supply agreement to March Point Cogeneration Company. Due to the nature of the obligation under this guarantee, a maximum
potential liability cannot be determined. TM

13

---

Star
has met its obligations to March Point Cogeneration Company, and, accordingly, no claims against this guarantee have been made.



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 contracts. In addition, subsidiaries of EME have guaranteed the obligations of Kern
River Cogeneration Company and Sycamore Cogeneration Company under their project power sales agreements to repay capacity payments to the projects' power purchaser in the event that the projects
unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. The obligations under the indemnification agreements as of
March 31, 2003, if payment were required, would be $200 million. EME has no reason to believe that any of these projects will either cease operations or reduce its electric power
producing capability during the term of its power contract.



EME has indemnified its lenders under its credit facilities from amounts drawn on a $35 million letter of credit issued for the benefit of the lenders to
ISAB Energy, a 49% unconsolidated affiliate, in lieu of ISAB Energy funding a debt service reserve account using additional equity contributions. Accordingly, a default under ISAB Energy's project
debt could result in a draw under the letter of credit which, in turn, would result in a borrowing under EME's credit facilities. The letter of credit is renewed each six-month period or
until ISAB Energy funds the debt service account. The indemnification is subject to the maximum amount drawn under the letter of credit. EME has not recorded a liability related to this indemnity.



A subsidiary of EME has indemnified Central Maine Power Company against decreases in the value of power deliveries by CL Power Sales Eight, L.L.C., an
unconsolidated affiliate, to Central Maine Power as a result of the implementation of a location-based pricing system in the New England Power Pool. The indemnity has the same term as a power supply
agreement between Central Maine Power and CL Eight, which runs through December 2016. It is not possible to determine potential differences in values between the various points of delivery in
New England Power Pool at this time. Due to the nature of this indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make a payment under
this indemnity, it and EME are indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for the acquisition of Citizens Power LLC. EME's subsidiary has not recorded a
liability related to this indemnity.



A subsidiary of EME has guaranteed the obligations of two unconsolidated affiliates to make payments to third parties for power delivered under fixed-price power
sales agreements. These agreements run through 2008. EME believes there is sufficient cash flow to pay the power suppliers assuming timely payment by the power purchasers. Due to the nature of this
indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make payments under the guarantee, EME's subsidiary and EME are indemnified by
Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

14

---

Environmental Matters and Regulations

EME is subject to environmental regulation by federal, state and local authorities in the United States and foreign regulatory authorities with jurisdiction over
projects located outside the United States. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will
not materially affect its financial position or results of operation. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future
proceedings that may be initiated by environmental authorities, could affect the costs and the manner in which EME conducts its business and could cause it to make substantial additional capital
expenditures. There is no assurance that EME would be able to recover these increased costs from its customers or that EME's financial position and results of operations would not be materially
adversely affected.

Typically,
environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the
necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital
expenditures. If EME fails to comply with applicable environmental laws, it may be subject to penalties and fines imposed against EME by regulatory authorities.

Note 8. Business Segments

EME operates predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific and
Europe. EME's plants are located in different geographic areas, which mitigate the effects of regional markets, economic downturns or unusual weather conditions.

|Three Months Ended                                                                 |                          | Americas |     | Asia Pacific |   | Europe |     | Corporate/
Other |     | Total |  
|---------------------------------------------------------------------------------- | ------------------------ | -------- | --- | ------------ | - | ------ | --- | ---------------- | --- | ----- | -
|
|March 31, 2003                                                                     |                          |          |     |              |   |        |     |                  |     |       |  
|Operating revenues from consolidated subsidiaries                                  |                          | $        | 367 |              | $ | 193    |     | $                | 132 |       | $
|Net gains (losses) from price risk management and energy trading                   |                          |          | 4   |              |   | (6     | )   |                  | (5  | )     |  
|                                                                                   |                          |          |     |              |   |        |     |                  |     |       |  
|                                                                                   | Total operating revenues |          | $   | 371          |   | $      | 187 |                  | $   | 127   |  
|                                                                                   |                          |          |     |              |   |        |     |                  |     |       |  
|Income (loss) from continuing operations before income taxes and minority interest |                          | $        | 39  |              | $ | 16     |     | $                | 24  |       | $
|                                                                                   |                          |          |     |              |   |        |     |                  |     |       |  
|March 31, 2002                                                                     |                          |          |     |              |   |        |     |                  |     |       |  
|Operating revenues from consolidated subsidiaries                                  |                          | $        | 259 |              | $ | 141    |     | $                | 115 |       | $
|Net gains (losses) from price risk management and energy trading                   |                          |          | 18  |              |   | (1     | )   |                  | 4   |       |  
|                                                                                   |                          |          |     |              |   |        |     |                  |     |       |  
|                                                                                   | Total operating revenues |          | $   | 277          |   | $      | 140 |                  | $   | 119   |  
|                                                                                   |                          |          |     |              |   |        |     |                  |     |       |  
|Income (loss) from continuing operations before income taxes and minority interest |                          | $        | (13 | )            | $ | 27     |     | $                | 25  |       | $
|                                                                                   |                          |          |     |              |   |        |     |                  |     |       |  

Note 9. Investments

The following table presents summarized financial information of the significant subsidiary investments in unconsolidated affiliates accounted for by the equity
method. The significant subsidiary investments include the California Power Group, Watson Cogeneration Company, Four Star Oil & Gas Company, PT Paiton Energy and ISAB Energy S.r.l. The
California Power Group (not a legal entity)

15

---

consists
of Kern River Cogeneration Company, Sycamore Cogeneration Company, Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas River Cogeneration Company, Sargent Canyon
Cogeneration Company, and Sunrise Power Company, LLC.

Three Months Ended
March 31,2003

2002(Unaudited)Operating revenues

$
560

$
401Operating income


143


113Net income


104


92


Note 10. Supplemental Statements of Cash Flows Information

Three Months Ended
March 31,2003

2002(Unaudited)Cash paidInterest (net of amount capitalized)

$
111

$
100Income taxes (receipts)

$
(2
)
$
(9
)Cash payments under plant operating leases

$
58

$
55Details of assets acquiredFair value of assets acquired

$
333

$
Liabilities assumed


58


Net cash paid for acquisitions

$
275

$



Note 11. Stock-based Compensation

Edison International has three stock-based employee compensation plans, which are described more fully in Note 15Stock Compensation Plans
included in EME's annual report on Form 10-K for the year ended December 31, 2002. EME accounts for those plans under the recognition and measurement principles of APB
Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Upon grant, no stock-based employee compensation cost is reflected in net income, as all options granted
under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income (loss) if EME had used
the fair value accounting method.

Three Months Ended
March 31,2003

2002(Unaudited)Net loss, as reported

$
(17
)
$
(50
)Add: stock-based compensation expense included in reported net loss, net of related tax effects


1


Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects


(1
)

Pro forma net loss

$
(17
)
$
(50
)


16

---

Note 12. Changes in Accounting

Statement of Financial Accounting Standards No. 143

Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS
No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. As of
January 1, 2003, EME recorded a $9 million, after tax, decrease to net income as the cumulative effect of adoption of SFAS No. 143.

EME
recorded a liability representing expected future costs associated with site reclamations, facilities dismantlement and removal of environmental hazards as follows:

Initial asset retirement obligation as of January 1, 2003

$
17Translation adjustments


1Balance of asset retirement obligation as of March 31, 2003 (unaudited)

$
18


For
the three months ended March 31, 2003, EME recognized accretion expense related to its asset retirement obligation of approximately $400,000. Had SFAS No. 143 been
applied retroactively in the three months ended March 31, 2002, it would not have had a material effect upon EME's results of operations.

Statement of Financial Accounting Standards Interpretation No. 45

In November 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about
its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a
liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective
basis to guarantees issued or modified after December 31, 2002. The adoption of this standard had no impact on EME's financial statements. See disclosure regarding guarantees and indemnities in
Note 7Commitments and Contingencies.

Statement of Financial Accounting Standards Interpretation No. 46

In January 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation
of Variable Interest Entities" (FIN 46). This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," addresses consolidation by business enterprises of
variable interest entities. The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through
means other than voting rights; such entities are known as variable-interest entities. This interpretation applies to variable interest entities created after January 31, 2003, and applies to
variable interest entities in which EME holds a variable interest that it acquired before February 1, 2003, beginning July 1, 2003.

Under
FIN 46, an enterprise that will (1) absorb a majority of a variable interest entity's expected losses (if they occur), (2) receive a majority of a variable interest
entity's expected residual returns (if they occur), or (3) both of the above, must consolidate the variable interest entity. The enterprise that

17

---

consolidates
the variable interest entity is called the primary beneficiary. EME believes it is reasonably possible that one or more of its investments in unconsolidated affiliates will be a variable
interest entity. Accordingly, EME is in the process of making this determination, and for investments in unconsolidated affiliates which are variable interest entities, a further determination will be
made if EME is the primary beneficiary.

EME
has concluded that it is the primary beneficiary of Brooklyn Navy Yard Cogeneration Partners L.P. since it is at risk with respect to a majority of its losses and is entitled to
receive a majority of its residual returns. Accordingly, EME will consolidate Brooklyn Navy Yard Cogeneration Partners L.P. effective July 1, 2003. In accordance with the transition provisions
of FIN 46, the consolidation of Brooklyn Navy Yard Cogeneration Partners L.P. will be based on the historical cost of the assets, liabilities and non-controlling interest which would have
been carried by EME effective when EME became the primary beneficiary. This means that EME will consolidate the assets and liabilities of Brooklyn Navy Yard Cogeneration Partners L.P. using the
June 30, 2003 balance sheet and eliminate intercompany balances. EME expects the consolidation of this entity to increase total assets by approximately $364 million and total liabilities
by approximately $435 million. Furthermore, EME expects to record a loss of approximately $71 million as a cumulative change of accounting as a result of consolidating this variable
interest entity. This loss is primarily due to cumulative losses allocated to the other 50% partner in excess of equity contributions recorded.

18

---



ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

The following discussion contains forward-looking statements. These statements are based on Edison Mission Energy's (EME's) knowledge of
present facts, current expectations about future events and assumptions about future developments. Forward-looking statements are not guarantees of performance; they are subject to risks,
uncertainties and assumptions that could cause actual future activities and results of operations to be materially different from those set forth in this discussion. Important factors that could cause
differences in EME's results of operations are set forth under "Market Risk Exposures" below, and under "Risk Factors" in the Management's Discussion and Analysis of Results
of Operations and Financial Condition included in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2002.

The Management's Discussion and Analysis of Results of Operations and Financial Condition of this Form 10-Q discusses material changes in the
results of operations, financial condition and other developments of EME since December 31, 2002, and as compared to the three months ended March 31, 2002. This discussion presumes that
the reader has read or has access to Management's Discussion and Analysis of Results of Operations and Financial Condition included in Item 7 of EME's annual report on Form 10-K for
the year ended December 31, 2002.

General

EME is an independent power producer engaged in the business of owning or leasing and operating electric power generation facilities worldwide. EME also conducts
price risk management and energy trading activities in power markets open to competition. EME is a wholly owned subsidiary of Mission Energy Holding Company. Edison International is EME's ultimate
parent company. Edison International also owns Southern California Edison Company, one of the largest electric utilities in the United States.

As
of March 31, 2003, EME owned or leased interests in 27 domestic and 54 international operating power plants with an aggregate generating capacity of 23,868 megawatts (MW), of
which EME's share was 18,823 MW. At that date, one domestic and two international power plants, totaling 615 MW of generating capacity, of which EME's anticipated share will be approximately 308 MW,
were under construction.

Current Developments

A number of significant developments during late 2001 and 2002 adversely affected independent power producers and subsidiaries of major integrated energy
companies that sell a sizable portion of their generation into the wholesale energy market (sometimes referred to as merchant generators), including several of EME's subsidiaries. These developments
included lower market prices in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of most major market participants, decreased
availability of debt financing or refinancing, and a resulting decline of liquidity in the energy markets due to growing concern about the ability of counterparties to perform their obligations. Since
the beginning of 2003, several merchant generators reached agreements to extend existing bank credit facilities.

EME's
largest subsidiary, Edison Mission Midwest Holdings, has $911 million of debt maturing in December 2003 which will need to be repaid, extended or refinanced. Edison
Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due in December 2003, and there is no assurance that Edison Mission Midwest Holdings will
be able to extend or refinance its debt obligation on similar terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into
by Mission Energy Holding Company in July 2001, or at all. EME's independent accountants' audit opinion for the year ended December 31,

19

---

2002
contains an explanatory paragraph that indicates the consolidated financial statements have been prepared on the basis that EME will continue as a going concern and that the uncertainty about
Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises substantial doubt about EME's ability to continue as a going concern. Accordingly, the consolidated
financial statements do not include any adjustments that might result from the resolution of this uncertainty.

During
the first quarter of 2003, wholesale energy prices in the Pennsylvania-New Jersey-Maryland Power Pool, or PJM, increased primarily due to
colder-than-normal weather and increases in the prices for natural gas. However, the recent changes in wholesale energy prices may or may not continue throughout 2003. See
"Market Risk Exposures" for more information regarding forward market prices.

Acquisitions and Dispositions of Investments in Energy Plants

Acquisitions

On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to acquire the Taranaki Combined Cycle
power station and related interests. The Taranaki station is a 357 MW combined cycle, natural gas-fired plant located near Stratford, New Zealand. Consideration for the Taranaki station
consisted of a cash payment of approximately $275 million, which was financed with bridge loan facilities. The bridge loan facilities were subsequently repaid with proceeds from the issuance of
long-term U.S. dollar denominated notes.

Dispositions

During the first quarter of 2002, EME completed the sales of its 50% interests in the Commonwealth Atlantic and James River projects and its 30% interest in the
Harbor project. Proceeds received from the sales were $44 million. During 2001, EME recorded asset impairment charges of $32 million related to these projects based on the expected sales
proceeds. No gain or loss was recorded from the sale of EME's interests in these projects during the first quarter of 2002.

20

---



RESULTS OF OPERATIONS

CONSOLIDATED OPERATING RESULTS

Net Income (Loss) Summary

Net loss is comprised of the following components:

Three Months Ended
March 31,2003

2002(Unaudited)
(in millions)Loss from continuing operations

$
(8
)
$
(41
)Income from discontinued operations





5Cumulative changes in accounting


(9
)

(14
)Net Loss

$
(17
)
$
(50
)


EME's
loss from continuing operations for the first quarter of 2003 was $8 million compared to $41 million for the first quarter of 2002. The 2003 reduction in loss from
continuing operations from 2002 was primarily due to higher PJM power prices and higher generation by EME's Homer City facilities, higher west coast energy prices and higher earnings from oil and gas
activities.

Operating Revenues

Operating revenues increased 27% for the first quarter of 2003, compared to the first quarter of 2002. The 2003 increase was primarily due to increased electric
revenues from the Illinois Plants, Homer City facilities and Contact Energy.

Net
gains (losses) from price risk management and energy trading activities is comprised of:

Three Months Ended
March 31,2003

2002(Unaudited)
(in millions)Price risk management

$
(22
)
$
4Energy trading


15


17Net Gains (Losses)

$
(7
)
$
21


Net
gains and (losses) from price risk management activities result from recording derivatives at fair value under Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS No. 133). Included in net gains (losses) from price risk management were:



21

---



Under
SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective
portion, is immediately recognized in earnings. EME recorded a net loss of approximately $8 million and $1 million during the first quarters of 2003 and 2002, respectively, representing
the amount of cash flow hedges' ineffectiveness. The net losses during the first quarter of 2003 are attributable to increases in the difference between energy prices at PJM West Hub (where EME's
subsidiary enters into forward contracts) and the energy prices at the delivery point where power generated by the Homer City facilities is delivered into the transmission system (referred to as the
Homer City busbar). See "Market Risk ExposuresAmericas" for more information regarding forward market prices.

The
2003 net gains from energy trading activities were primarily the result of net gains from transmission congestion contracts and other power contracts in markets where EME has power
plants. The 2002 net gains from energy trading activities primarily represent the completion of the
restructuring of a power sales agreement with an unaffiliated electric utility. As part of the transaction, an EME subsidiary purchased the power sales agreement held by a third party, modified its
terms and conditions, and entered into a long-term power supply agreement with another party. Although the sale and purchase of power arising from these contracts will occur over their
term, net gains of $17 million were recorded during the first quarter of 2002 attributable to the fair value of the contracts (generally referred to as mark-to-market
accounting).

EME's
third quarter electric revenues are materially higher than revenues related to other quarters of the year because warmer weather during the summer months results in higher electric
revenues being generated from the Homer City facilities and the Illinois Plants. By contrast, the First Hydro plants have higher electric revenues during their winter months.

Operating Expenses

Fuel costs increased $72 million for the first quarter of 2003, compared to the first quarter of 2002. Fuel costs in 2003 increased primarily due to
increased generation from the Illinois Plants and the Homer City facilities.

Plant
operations and transmission costs increased $20 million for the first quarter of 2003, compared to the first quarter of 2002. Transmission costs were $55 million and
$36 million for the first quarters of 2003 and 2002, respectively. The 2003 increase in transmission costs was primarily due to higher retail sales generated by Contact Energy.

Depreciation
and amortization expense increased $14 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 increase is primarily due to higher
amortization expense resulting from the adoption of SFAS No. 142 at Contact Energy. In addition, depreciation expense increased in the first quarter of 2003 from the first quarter of 2002,
resulting from the termination of the Midwest Generation equipment lease in August 2002.

Administrative
and general expenses decreased $7 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 decrease was primarily due to cost
reductions implemented in 2002. During the first quarter of 2002, EME severance and other related costs were $4 million.

Other Income (Expense)

Equity in income from unconsolidated affiliates increased 21% for the first quarter of 2003, compared to the first quarter of 2002. The 2003 increase was
primarily due to an increase in EME's share of income from the Big 4 projects and Four Star Oil & Gas. EME's third quarter equity in income from its domestic energy projects is materially
higher than equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of

22

---

EME's
domestic energy projects, located on the west coast, have power sales contracts that provide for higher payments during the summer months.

Interest
and other income decreased $3 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 decrease was primarily due to lower interest income.

Interest
expense increased $4 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 increase was due to higher interest costs at the Illinois
Plants due to a downgrade of the credit rating of Edison Mission Midwest Holdings and higher levels of borrowings at Contact Energy. See "Liquidity and Capital
ResourcesCredit Ratings."

Income Taxes

EME's annual effective tax rate (excluding state tax reallocation benefits) was 41% in the first quarter of 2003 compared to 47% in the first quarter of 2002.
During the first quarter of 2003, EME recorded $5 million of additional state tax benefits net of federal income taxes, as a result from participation in a tax-allocation agreement
with Edison International.

Minority Interest

Minority interest expense decreased $1 million for the first quarter of 2003, compared to the first quarter of 2002. Minority interest primarily relates to
49% ownership of Contact Energy by the public in New Zealand.

Discontinued Operations

Lakeland Project

EME's Lakeland project operated a 220 MW combined cycle, natural gas-fired power plant located in the United Kingdom. The assets of the project are
owned by EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU (UK)
Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe).

On
December 19, 2002, the lenders to the Lakeland project accelerated the debt owing under the bank agreement that governs the project's indebtedness, and on December 20,
2002, the Lakeland project lenders appointed an administrative receiver over the assets of Lakeland Power Ltd. The administrative receiver was appointed to take control of the affairs of
Lakeland Power Ltd. and has a wide range of powers (specified in the Insolvency Act), including authorizing the sale of the power plant. The appointment of the administrative receiver requires
the treatment of Lakeland power plant as an asset held for sale under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets" (SFAS No. 144). Due to EME's loss of control arising from the appointment of the administrative receiver, EME no longer consolidates the activities of Lakeland Power Ltd. The
consolidated financial statements have been restated to conform to discontinued operations treatment for all historical periods presented.

On
April 22, 2003, a third party announced that it had entered an agreement with the administrative receiver to purchase the Lakeland power plant for
£24 million. Subject to satisfaction of closing conditions, completion of the sale is expected during the second quarter of 2003.

During
the first quarter of 2002, EME recorded income of $5 million from discontinued operations primarily related to operating income from the Lakeland power plant.

23

---

Cumulative Effect of Change in Accounting Principle

Statement of Financial Accounting Standards No. 142

Effective January 1, 2002, EME adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS
No. 142 establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. EME will perform
its annual evaluation of goodwill on October 1, 2003 or sooner if indicators of impairment exist. During the third quarter of 2002, EME concluded that fair value of the goodwill related to the
Citizens Power LLC acquisition was impaired by $14 million, net of $9 million of income tax benefit and, accordingly, reported this amount as a cumulative change in accounting. In
accordance with SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements," EME's financial statements for the first quarter of 2002 were restated to reflect the accounting
change as of January 1, 2002.

Statement of Financial Accounting Standards No. 143

Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS
No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. As of
January 1, 2003, EME recorded a $9 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 143.

REGIONAL OPERATING RESULTS

EME operates predominantly in one line of business, electric power generation, organized by three geographic regions: Americas, Asia Pacific, and Europe.
Operating revenues are derived from EME's majority-owned domestic and international entities. Intercompany interest expense and income between EME and its consolidated subsidiaries have been
eliminated in the following project results, except as described below with respect to loans provided to EME from a wholly owned subsidiary, Midwest Generation. Equity in income from unconsolidated
affiliates relates to energy projects where EME's ownership interest is 50% or less in the projects. The equity method of accounting is generally used to account for the operating results of entities
over which EME has a significant influence but in which it does not have a controlling interest. With respect to entities accounted for under the equity method, EME recognizes its proportional share
of the income or loss of such entities.

EME uses the words "earnings" or "losses" in this section to describe income or loss from continuing operations before income taxes and minority
interest.

24

---

Americas

Three Months Ended
March 31,2003

2002(Unaudited)
(in millions)Operating Revenues from Consolidated SubsidiariesIllinois Plants

$
212

$
166Homer City


149


86Other


6


7$
367

$
259Income (Loss) before Taxes and Minority Interest (Earnings/Losses)Consolidated operationsIllinois Plants


(42
)

(44
)Homer City


46


2Other


13


21Unconsolidated affiliatesBig 4 projects


17


1Four Star Oil & Gas


15


7Sunrise


(1
)

(1
)March Point


3


3Other


(2
)

9Regional overhead


(10
)

(11
)$
39

$
(13
)


Illinois Plants

Three Months Ended
March 31,2003

2002StatisticsCoal-Fired GenerationGeneration (in GWhr):Power purchase agreement


3,600


5,998Merchant


3,204


236Total coal-fired generation


6,804


6,234Availability(1)


75.3
%

81.1
%Forced outage rate(2)


6.7
%

4.0
%Average realized energy price/MWh:Power purchase agreement

$
18.02

$
16.70Merchant

$
25.48

$
19.49Total coal-fired generation

$
21.53

$
16.81Capacity revenues (in millions)

$
32

$
52


---

25

---

In accordance with the power purchase agreements, Exelon Generation released 4,548 MW of generating capacity during 2002 from the power purchase agreements at the Illinois Plants. Of the
generating capacity released by Exelon Generation, EME's subsidiary suspended operations for 1,370 MW and decommissioned 45 MW. As a result, beginning in 2003, the Illinois Plants have 3,133 MW
available for sale as merchant generation. Operating revenues from the Illinois Plants increased $46 million for the first quarter of 2003, compared to the first quarter of 2002, primarily due
to increased merchant generation at the coal plants released by Exelon Generation. Operating revenues were also higher due to average realized energy prices from merchant generation due to
colder-than-normal weather, partially offset by lower capacity revenue from the reduction in megawatts contracted under the power purchase agreements. The average realized
prices from merchant generation during the first quarter of 2003 were less than the actual spot market prices during that period due to forward contracts entered into during 2002 (prior to the
increase in spot market prices that took place during the first quarter of 2003) for approximately 52% of the Illinois Plants' actual merchant generation. See "Market Risk
ExposuresIllinois Plants."

Exelon
Generation is obligated under the power purchase agreements to make capacity payments for the plants under contract (4,739 MW during 2003) and energy payments for
electricity produced by these plants. As a result of the decline in contracted generating capacity under the power purchase agreements, revenues from Exelon Generation as a percentage of EME's
consolidated operating revenues decreased from 30% for the first quarter of 2002 to 19% for the first quarter of 2003. Revenues from Exelon Generation were $131 million and $161 million
for the first quarters of 2003 and 2002, respectively. For more information on the power purchase agreements and wholesale energy markets, see "Market Risk ExposuresIllinois
Plants."

Losses
from the Illinois Plants decreased $2 million for the first quarter of 2003, compared to the first quarter of 2002, due to the following factors:



The
losses of the Illinois Plants included interest income of $28 million and $31 million for the first quarters of 2003 and 2002, respectively, related to loans to EME. In
August 2000, Midwest Generation, which owns or leases the Illinois Plants, entered into a sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds from the sale of
these facilities were loaned to EME, which also provided a guarantee of the related lease obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded as an operating
lease for accounting purposes.

Homer City

Three Months Ended
March 31,2003

2002StatisticsGeneration (in GWhr)


3,620


2,695Availability(1)


88.9
%

67.2
%Forced outage rate(2)


6.7
%

28.7
%Average realized energy price/MWh

$
39.82

$
26.65Capacity revenues (in millions)

$
3

$
13


---

26

---



Operating
revenues from Homer City increased $63 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 increase primarily resulted from higher
electric revenues from the Homer City facilities due to increased generation and higher energy prices. On February 10, 2002, Homer City experienced a major unplanned outage due to a collapse of
the SCR ductwork of one of the units, known as Unit 3. The unit was restored to operation on April 4, 2002 and is operating with the SCR bypassed.

Earnings
from Homer City increased $44 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 increase in earnings is due to increased generation
and higher energy prices. See "Market Risk ExposuresHomer City Facilities."

Losses
from price risk management activities were $8 million for the first quarter of 2003. The losses primarily represent the ineffective portion of forward contracts which are
derivatives that qualify as cash flow hedges under SFAS No. 133. No comparable amount was recorded the first quarter of 2002. See "Consolidated Operating
ResultsOperating Revenues" for further discussion.

Big 4 Projects

EME owns partnership investments (50% ownership or less) in Kern River Cogeneration Company, Midway-Sunset Cogeneration Company, Sycamore Cogeneration Company and
Watson Cogeneration Company. These projects have similar economic characteristics and have been used, collectively, to secure bond financing by Edison Mission Energy Funding Corp., a special purpose
entity that EME includes in its consolidated financial statements. Due to similar economic characteristics and the bond financing related to EME's equity investments in these projects, EME evaluates
them collectively and refers to them as the Big 4 projects.

Earnings
from the Big 4 projects increased $16 million for the first quarter of 2003, compared to the first quarter of 2002. The change in earnings was largely due to higher
energy prices in 2003. The earnings from the Big 4 projects included interest expense from Edison Mission Energy Funding of $4 million and $5 million for the first quarters of 2003 and
2002, respectively.

Four Star Oil & Gas

EME owns a 37.2% direct and indirect interest, with 36.05% voting stock, in Four Star Oil & Gas Company, with majority control held by affiliates of
ChevronTexaco Corporation. Four Star Oil & Gas owns oil and gas reserves in the San Juan Basin, the Hugoton Basin, the Permian Basin and offshore Gulf Coast and Alabama. EME's share of earnings
from Four Star Oil & Gas Company was $15 million and $7 million for the first quarters of 2003 and 2002, respectively. The 2003 increase in earnings was primarily due to higher
natural gas prices.

Other

Earnings from other projects in the Americas region (consolidated subsidiaries and unconsolidated affiliates) included net gains from energy trading activities of
$15 million and $17 million for the first quarters of 2003 and 2002, respectively. See "Consolidated Operating ResultsOperating Revenues" for further
discussion.

27

---

Asia Pacific

Three Months Ended
March 31,2003

2002(Unaudited)
(in millions)Operating Revenues from Consolidated SubsidiariesContact Energy

$
143

$
95Loy Yang B


36


37Other


14


9$
193

$
141Income (Loss) before Taxes and Minority Interest (Earnings/Losses)Consolidated operationsContact Energy(1)


5


7Loy Yang B


3


9Other


3


3Unconsolidated affiliatesPaiton


9


12Other


(2
)

(1
)Regional overhead


(2
)

(3
)$
16

$
27


---

Contact Energy

Operating revenues increased $48 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 increase was primarily due to
higher wholesale electricity prices and higher generation. In addition, there was a 29% increase in the average exchange rate of the New Zealand dollar compared to the U.S. dollar during the first
quarter of 2003, compared to the first quarter of 2002.

Earnings
from Contact Energy, included in the consolidated statements of income of EME as described above, decreased $2 million for the first quarter of 2003, compared to the
first quarter of 2002. The 2003 decrease is primarily due to a $6 million loss from price risk management activities for the first quarter of 2003 related to a change in market value of
electricity and financial contracts that were not designated as cash flow hedges for hedge accounting under SFAS No. 133. No comparable amount was recorded for the first quarter of 2002.

Loy Yang B

Operating revenues decreased $1 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 decrease in operating revenues is
primarily due to lower generation resulting from a planned outage in March 2003 and lower pool prices for the power sold into the wholesale energy market. The 2003 decrease was partially offset
by a 14% increase in the average exchange rate

28

---

of
the Australian dollar compared to the U.S. dollar during the first quarter of 2003, compared to the first quarter of 2002.

Earnings
from Loy Yang B decreased $6 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 decrease in earnings is due to lower electric revenues
discussed above and higher plant maintenance costs related to the planned outage in March 2003.

Paiton Energy

Earnings from Paiton Energy decreased $3 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 decrease in earnings is
primarily due to an unplanned outage during the first quarter of 2003.

Other

Operating revenues from other consolidated subsidiaries increased $5 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003
increase in operating revenues is primarily due to higher electric revenues from the Valley Power Peaker project in Australia. Commercial operation of the Valley Power Peaker project commenced during
the second quarter of 2002.

Regional G&A

Asia Pacific's Regional G&A decreased $1 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 decrease in Regional G&A
was primarily due to cost reductions implemented in 2002.

Europe(1)

Three Months Ended
March 31,2003

2002(Unaudited)
(in millions)Operating Revenues from Consolidated SubsidiariesFirst Hydro

$
91

$
79Doga(2)


33


30Other


8


6$
132

$
115Income (Loss) before Taxes and Minority Interest (Earnings/Losses)Consolidated operationsFirst Hydro


5


12Doga


4


6Other


4


3Unconsolidated affiliatesISAB


11


9Other


4


1Regional overhead


(4
)

(6
)$
24

$
25


---

29

---



First Hydro

Operating revenues increased $12 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 increase resulted primarily from
higher electric revenues from the First Hydro plant due to increased volumes of power sales and a 12% increase in the average exchange rate of the British pound compared to the U.S. dollar during the
first quarter of 2003, compared to the first quarter of 2002. These increases were partially offset by lower ancillary services revenues during the first quarter of 2003 from the first quarter of
2002. The First Hydro plant is expected to provide for higher electric revenues during its winter months.

Earnings
from First Hydro decreased $7 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 decrease in earnings is primarily due to a
$5 million loss from price risk management activities for the first quarter of 2003, compared to a $4 million gain from price risk management activities for the first quarter of 2002.
First Hydro's gains (losses) from price risk management relate to realized losses and the change in market value of commodity contracts that are recorded at fair value under SFAS No. 133, with
changes in fair value recorded through the income statement.

Doga

Revenues from Doga increased $3 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 increase is due to an increase in
electricity generation, higher steam sales and higher natural gas prices. Earnings from Doga decreased $2 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003
decrease in earnings is primarily due to higher fuel costs and plant costs, partially offset by higher electric revenues discussed above.

ISAB

Earnings from ISAB increased $2 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 increase was primarily due to higher
generation in the first quarter of 2003, compared to the first quarter of 2002.

Other

Earnings from other projects in the Europe region (consolidated subsidiaries and unconsolidated affiliates) increased $4 million for the first quarter of
2003, compared to the first quarter of 2002. The 2003 increase in earnings is primarily due to increased operating revenues from EME's Spanish Hydro project largely due to higher generation caused by
more rainfall in the first quarter of 2003, compared to the first quarter of 2002.

Regional G&A

Europe's Regional G&A decreased $2 million for the first quarter of 2003, compared to the first quarter of 2002. The 2003 decrease in Regional G&A is
primarily due to lower development costs.

30

---



LIQUIDITY AND CAPITAL RESOURCES

At March 31, 2003, EME and its subsidiaries had cash and cash equivalents of $654 million and EME had available a total of $274 million of
borrowing capacity under its $487 million corporate credit facility. EME's consolidated debt at March 31, 2003 was $6.4 billion, including $911 million of debt maturing in
December 2003 which is owed by EME's largest subsidiary, Edison Mission Midwest Holdings. In addition, EME's subsidiaries have $7 billion of long-term lease obligations that
are due over a period ranging up to 32 years.

The
$911 million of debt of Edison Mission Midwest Holdings maturing in December 2003 will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings is not
expected to have sufficient cash to repay the $911 million debt due in December 2003, and there is no assurance that it will be able to extend or refinance its debt obligation on similar
terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into by Mission Energy Holding Company in July 2001, or at
all. EME's independent accountants' audit opinion for the year ended December 31, 2002 contains an explanatory paragraph that indicates the consolidated financial statements have been prepared
on the basis that EME will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises substantial doubt
about EME's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this uncertainty.

Credit Ratings

Credit ratings for EME and its subsidiaries, Edison Mission Midwest Holdings and Edison Mission Marketing & Trading, are as follows:

Moody's Rating

S&P RatingEdison Mission Energy (senior unsecured)

Ba3

BBEdison Mission Midwest Holdings (bank facility)

Ba2

BBEdison Mission Marketing & Trading (senior unsecured)

Not Rated

BB


Standard &
Poor's has assigned a negative rating outlook for each of these entities. Moody's has Edison Mission Energy's and Edison Mission Midwest Holdings' ratings under review
for further downgrade.

The
credit ratings of EME are below investment grade and, accordingly, EME has agreed to provide collateral in the form of cash and letters of credit for the benefit of counterparties
for its price risk management and domestic trading activities related to accounts payable and unrealized losses ($65 million as of May 9, 2003). EME has also provided collateral for a
portion of its United Kingdom trading activities. To this end, EME's subsidiary, Edison Mission Operation and Maintenance Limited, has obtained a cash collateralized credit facility, under which
letters of credit totaling £17 million have been issued as of April 30, 2003.

EME
anticipates that sales of power from its Illinois Plants, Homer City facilities and First Hydro plants in the United Kingdom may require additional credit support, depending upon
market conditions and the strategies adopted for the sale of this power. Changes in forward market prices and margining requirements could further increase the need for credit support for the price
risk management and trading activities related to these projects. EME currently projects the potential working capital to support its price risk management and trading activity to be between
$100 million and $200 million from time to time during 2003.

EME
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

31

---

lowered
again. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised or withdrawn at any time by a rating agency.

Credit Rating of Edison Mission Midwest Holdings

As a result of the downgrade of Edison Mission Midwest Holdings below investment grade in October 2002, provisions in the agreements binding on Edison
Mission Midwest Holdings and Midwest Generation restrict the ability of Edison Mission Midwest Holdings to make distributions to its parent company, thereby eliminating distributions to EME.

The
following table summarizes the provisions restricting cash distributions (sometimes referred to as cash traps) and the related changes in the cost of borrowing by Edison Mission
Midwest Holdings under the applicable financing agreements. The currently applicable provisions are those set forth in the same row as the Standard & Poor's rating "BB."

S&P Rating

Moody's Rating

Cost of Borrowing
Margin

Cash Trap(based on LIBOR)BBB or higher

Baa3 or higher

150

No cash trapBB+

Ba1

225

50% of excess cash flow trapped until six month debt service reserve is fundedBB

Ba2

275

100% of excess cash flow trappedBB

Ba3

325

100% of excess cash flow trappedB+

B1

325

100% of excess cash flow trapped and used to repay debt


Based
on its current credit rating, provisions in the agreements binding on Edison Mission Midwest Holdings require it to deposit, on a quarterly basis, 100% of its excess cash flow as
defined in the agreements into a cash flow recapture account held and maintained by the collateral agent. In accordance with these provisions, Edison Mission Midwest Holdings deposited
$50 million into the cash flow recapture account on October 31, 2002, and another $28 million on January 27, 2003. The funds in the cash flow recapture account may be used
only to meet debt service obligations of Edison Mission Midwest Holdings if funds are not otherwise available from working capital. There is no assurance that Edison Mission Midwest Holdings' current
credit rating will not be lowered again, in which case Edison Mission Midwest Holdings would be required to use its defined excess cash flow, as well as cash in the cash flow recapture account, to
repay indebtedness.

As
part of the sale-leaseback of the Powerton and Joliet power stations, Midwest Generation loaned the proceeds ($1.4 billion) to EME in exchange for promissory notes
in the same aggregate amount. Debt service payments by EME on the promissory notes may be used by Midwest Generation to meet its payment obligations under these leases in whole or part. Furthermore,
EME has guaranteed the lease obligations of Midwest Generation under these leases. EME's obligations under the promissory notes payable to Midwest Generation are general corporate obligations of EME
and are not contingent upon receiving distributions from Edison Mission Midwest Holdings. See "Restricted Assets of EME's SubsidiariesEdison Mission Midwest Holdings
(Illinois Plants)" for a discussion of implications for the Powerton and Joliet leases.

Credit Rating of Edison Mission Marketing & Trading

Pursuant to the Homer City sale-leaseback documents, a below investment grade credit rating of Edison Mission Marketing & Trading restricts the
ability of EME Homer City Generation L.P. (EME Homer City) to enter into permitted trading activities, as defined in the documents, with Edison Mission Marketing & Trading to sell forward the
output of the Homer City facilities. These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting as

32

---

seller
to an unaffiliated third party, be investment grade. EME currently sells all of the output from the Homer City facilities through Edison Mission Marketing & Trading, 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 Edison Mission Marketing & Trading; or (2) Edison
Mission Marketing & Trading 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, 2004. EME is permitted to sell the output
of the Homer City facilities into the PJM at any time on a spot-market basis. See "Market Risk ExposuresHomer City Facilities."

Corporate Liquidity

EME has a $487 million corporate credit facility which includes a $275 million component, Tranche A, that expires on September 16, 2003 and a
$212 million component, Tranche B, that expires on September 17, 2004. At March 31, 2003, EME had borrowing capacity under this facility of $274 million and corporate cash
and cash equivalents of $31 million.

Cash
distributions from EME's subsidiaries and partnership investments, tax-allocation payments from Edison International and unused capacity under its corporate credit
facilities represent EME's major sources of liquidity to meet its cash requirements. In addition, EME expects to complete the Sunrise project financing during the summer of 2003 which, upon
completion, will result in the receipt by EME of approximately $140 million to $150 million of capital previously invested in this project. See "Subsidiary Financing Plans." EME expects
its 2003 cash requirements to be primarily comprised of:



The
timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "Historical Distributions Received by Edison Mission
EnergyRestricted Assets of EME's Subsidiaries." Also see "Risk Factors" in the Management's Discussion and Analysis of Results of Operations and Financial Condition included
in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2002. In addition, the right of EME to receive tax-allocation payments, and the
timing and amount of tax-allocation payments received by EME are subject to factors beyond EME's control. See "Intercompany Tax-Allocation Payments." If Tranche A
of the corporate facility is not extended and the Sunrise project financing is not completed as scheduled, EME's ability to provide credit support for bilateral contracts for power and fuel of its
merchant energy operations will be severely limited. If EME is unable to provide such credit support, this will reduce the number of counterparties willing to enter into bilateral contracts with EME's
subsidiaries, thus requiring EME's subsidiaries to rely on short-term markets instead of bilateral contracts. Furthermore, if this situation occurs, EME may not be able to meet margining
requirements if forward prices for power increase significantly. Failure to meet a margining requirement would permit the counterparty to terminate the related bilateral contract early and demand
immediate payment for the replacement value of the contract.

EME's
corporate credit facility provides credit available in the form of cash advances or letters of credit. At March 31, 2003, Tranche A consisted of borrowings of
$80 million, and $132 million of letters

33

---

of
credit were outstanding under Tranche B. In addition to the interest payments, EME pays a facility fee determined by its long-term credit ratings (0.875% and 1.00% at March 31,
2003 for Tranche A and Tranche B, respectively) on the entire credit facility independent of the level of borrowings.

Under
the credit agreement governing its credit facility, EME has agreed to maintain an interest coverage ratio that is based on cash received by EME, including
tax-allocation payments, cash disbursements and interest paid. At March 31, 2003, EME met this interest coverage ratio. The interest coverage ratio in the ring-fencing
provisions of EME's certificate of incorporation and bylaws remains relevant for determining EME's ability to make distributions. See "Interest Coverage Ratio."

Discussion of Historical Cash Flow

Cash Flows From Operating Activities

Net cash provided by (used in) operating activities:

Three Months Ended
March 31,2003

2002(Unaudited)
(in millions)Continuing operations

$
(2
)
$
11Discontinued operations





$
(2
)
$
11


The
lower operating cash flow from continuing operations in the first quarter of 2003, compared to the first quarter of 2002, reflects lower distributions from unconsolidated affiliates.
Distributions from unconsolidated affiliates during the first quarter of 2002 were higher than the first quarter of 2003 primarily due to the collection of past due accounts receivable from California
utilities, arising from the
California energy crisis, by EME's investments in California qualifying facilities which amounts were then distributed to their partners. EME received $13 million in tax-allocation
payments from Edison International during the first three months of 2003, partially offsetting the cash used in operating activities. For further discussion on the tax-allocation payments,
see "Intercompany Tax-Allocation Payments." The change in operating cash flow from continuing operations in the first quarter of 2003 was also due to the timing of cash
receipts and disbursements related to working capital items.

Cash Flows From Financing Activities

Net cash provided by (used in) financing activities:

Three Months Ended
March 31,2003

2002(Unaudited)
(in millions)Continuing operations

$
323

$
(27
)Discontinued operations





(4
)$
323

$
(31
)


Cash
provided by financing activities from continuing operations during the first quarter of 2003 consisted of net borrowings of $80 million on EME's $487 million corporate
credit facility and $320 million in borrowings by Contact Energy, EME's 51% owned subsidiary, of which $275 million was used to finance the acquisition of the Taranaki power station.
Debt service payments of $23 million related to one of EME's subsidiaries were made in March 2003.

34

---

Cash
used in financing activities from continuing operations during the first quarter of 2002 consisted of net payments of $80 million on EME's corporate credit facility and
$22 million related to debt service payments of one of EME's subsidiaries. In addition, a wholly owned subsidiary borrowed $84 million under a note purchase agreement in
January 2002.

Cash Flows From Investing Activities

Net cash used in investing activities:

Three Months Ended
March 31,2003

2002(Unaudited)
(in millions)Continuing operations

$
(328
)
$
(2
)Discontinued operations


4


1$
(324
)
$
(1
)


Cash
used in investing activities from continuing operations during the first quarter of 2003 included $275 million paid by Contact Energy for the acquisition of the Taranaki
power station during the first quarter of 2003 and $23 million in equity contributions to the Sunrise and CBK projects. EME invested $56 million in the first quarter of 2003 in new plant
and equipment principally related to the Illinois Plants and the Homer City facilities.

Cash
used in investing activities from continuing operations during the first quarter of 2002 included $80 million paid for the purchase of a power sales agreement held by a third
party. EME invested
$72 million in the first quarter of 2002 in new plant and equipment principally related to the Valley Power Peaker project in Australia, the Illinois Plants and the Homer City facilities. Also,
included in capital expenditures during the first quarter of 2002 were payments for three turbines purchased under EME's Master Turbine Lease with funds from restricted cash of $61 million.
Included in first quarter 2002 investing activities was $86 million of restricted cash used to purchase the three turbines and satisfy EME's obligation related to the termination of EME's
Master Turbine Lease, thereby reducing EME's restricted cash account. EME received proceeds of $44 million from the sales of its 50% interests in the Commonwealth Atlantic and James River
projects and its 30% interest in the Harbor project during the first quarter of 2002. In addition, EME received $78.5 million as a return of capital from the Kern River and Sycamore projects
subsequent to their receipt of payments of past due accounts receivable from Southern California Edison during the first quarter of 2002.

Historical Distributions Received By Edison Mission Energy

The following table is presented as an aid in understanding the cash flow of EME and its various subsidiary holding companies which depend on distributions from
subsidiaries and affiliates to fund general and administrative costs and interest costs of recourse debt. Distributions for the first three

35

---

months
of each year are not necessarily indicative of annual distributions due to the seasonal fluctuations in EME's business.

March 31,
2003

March 31,
2002(Unaudited)
(in millions)Distributions from Consolidated Operating Projects:EME Homer City Generation L.P. (Homer City facilities)

$
21

$
Holding companies of other consolidated operating projects


36


4Distributions from Non-Consolidated Operating Projects:Edison Mission Energy Funding Corp. (Big 4 Projects)(1)


20


82Four Star Oil & Gas Company





4Holding companies of other non-consolidated operating projects


23


24Total Distributions

$
100

$
114


---

Total
distributions to EME decreased due to:



Partially
offset by:



Restricted Assets of EME's Subsidiaries

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

36

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Edison Mission Midwest Holdings Co. (Illinois Plants)

Edison Mission Midwest Holdings Co. is the borrower under a $1.9 billion credit facility with a group of commercial banks. The funds borrowed under this
facility were used to fund the acquisition of the Illinois Plants and provide working capital to such operations. Midwest Generation, a wholly owned subsidiary of Edison Mission Midwest Holdings, owns
or leases and operates the Illinois Plants. Midwest Generation entered into sale-leaseback transactions for the Collins Station as part of the original acquisition and for the Powerton
Station and the Joliet Station in August 2000. In order for Edison Mission Midwest Holdings to make a distribution, Edison Mission Midwest Holdings and Midwest Generation must be in compliance
with the covenants specified in these agreements, including maintaining a minimum credit rating. Because Edison Mission Midwest Holdings' credit rating is below investment grade, no distributions can
currently be made by Edison Mission Midwest Holdings to its parent company and ultimately, to EME at this time. See "Credit Ratings."

Edison
Mission Midwest Holdings must also maintain a debt service coverage ratio for the prior twelve-month period of at least 1.50 to 1 as long as the power purchase agreements with
Exelon Generation represent 50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenues. If the power purchase agreements with Exelon Generation represent less than 50% of Edison
Mission Midwest Holdings' and its subsidiaries' revenues, it must maintain a debt service coverage ratio of at least 1.75 to 1. EME expects that revenues for 2003 from Exelon Generation will represent
50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenues. In addition, Edison Mission Midwest Holdings must maintain a debt-to-capital ratio no greater
than 0.60 to 1. Failure to meet the historical debt service coverage ratio and the debt-to-capital ratio are events of default under the credit agreement and Collins lease
agreements, which, upon a vote by a majority of the lenders, could cause an acceleration of the due date of the obligations of Edison Mission Midwest Holdings and those associated with the Collins
lease. Such an acceleration would result in an event of default under the Powerton and Joliet leases. During the 12 months ended March 31, 2003, the historical debt service coverage
ratio was 3.77 to 1 and the debt-to-capital ratio was 0.52 to 1.

There
are no restrictions on the ability of Midwest Generation to make payments on the outstanding intercompany loans from its affiliate Edison Mission Overseas Co. (which is also a
subsidiary of Edison Mission Midwest Holdings) or to make distributions directly to Edison Mission Midwest Holdings.



EME Homer City Generation L.P. completed a sale-leaseback of the Homer City facilities in December 2001. In order to make a distribution, EME
Homer City must be in compliance with the covenants specified in the lease agreements, including the following financial performance requirement measured on the date of distribution:



At
the end of each quarter, the equity and debt portions of rent then due and payable must have been paid. The senior rent service coverage ratio (discussed in the bullet point above)
projected for each of the prospective two twelve-month periods must be greater than 1.7 to 1. No more than two rent default events may have occurred, whether or not cured. A rent default event is
defined as the failure to pay the equity portion of the rent within five business days of when it is due.

37

---

During
the 12 months ended March 31, 2003, the senior rent service coverage ratio was 4.2 to 1.



A subsidiary of First Hydro Holdings, First Hydro Finance plc, is the borrower of £400 million of Guaranteed Secured Bonds due in 2021. In
order to make a distribution, First Hydro Finance must be in compliance with the covenants specified in its bond indenture, including an interest coverage ratio. When measured for the twelve-month
period ended December 31, 2002, First Hydro Holdings met the interest coverage ratio and made a distribution of $18 million on May 7, 2003.

On
March 14, 2003, First Hydro Finance plc received a letter from the trustee for the First Hydro bonds, requesting that First Hydro Finance engage in a process to determine
whether an early redemption option in favor of the bondholders has been triggered under the terms of the First Hydro bonds. This letter states that, given requests made of the trustee by a group of
First Hydro bondholders, the trustee needs to satisfy itself whether the termination of the pool system in the United Kingdom (replaced with the new electricity trading arrangements, referred to as
NETA), was materially prejudicial to the interests of the bondholders. If this were the case, it could provide the First Hydro bondholders with an early redemption option. In this regard, on
August 29, 2000, First Hydro Finance notified the trustee that the enactment of the Utilities Act of 2000, which laid the foundation for NETA, would result, after its implementation, in a so
called restructuring event under the terms of the First Hydro bonds. However, First Hydro Finance did not believe then, nor does it believe now, that this event was materially prejudicial to the First
Hydro bondholders. Since NETA implementation, First Hydro Finance has continued to meet all of its debt service obligations and financial covenants under the bond documentation, including the required
interest coverage ratio. Until its receipt of the trustee's March 14, 2003 letter, First Hydro Finance had not received a response from the trustee to its August 29, 2000 notice. First
Hydro Finance will dispute any attempt to have the early redemption option deemed applicable due to NETA implementation.

Neither
the August 2000 notice provided to the trustee, nor the March 14, 2003 letter from the trustee constitutes an event of default under the terms of the First Hydro
bonds; and there is no recourse to EME for the obligations of First Hydro Finance in respect of the First Hydro bonds. However, if the bondholders were entitled to an early redemption option, First
Hydro Finance would be obligated to purchase all First Hydro bonds put to it by bondholders at par plus an early redemption premium. If all bondholders opted for the early redemption option, it is
unlikely that First Hydro Finance would have sufficient financial resources to so purchase the bonds. There is no assurance that First Hydro Finance would be able to obtain additional financing to
fund the purchase of the First Hydro bonds. Therefore, an exercise of the early redemption option by the bondholders could lead to administration proceedings as to First Hydro Finance in the United
Kingdom, which is similar to Chapter 11 bankruptcy proceedings in the United States. If these events were to occur, it would have a material adverse effect upon First Hydro Finance and could have a
material adverse effect upon EME.

Edison Mission Energy Funding Corp. (Big 4 Projects)

EME's subsidiaries, which EME refers to, in this context, as the guarantors, that hold EME's interests in the Big 4 projects completed a $450 million
secured financing in December 1996. Edison Mission Energy Funding Corp., a special purpose Delaware corporation, issued notes ($260 million) and bonds ($190 million), the net
proceeds of which were lent to the guarantors in exchange for a note. The guarantors have pledged their cash proceeds from the Big 4 projects to Edison Mission Energy Funding as collateral for the
note. All distributions receivable by the guarantors from the Big 4 projects are deposited into a trust account from which debt service payments are made on the obligations of Edison Mission Energy
Funding and from which distributions may be made to EME if Edison Mission

38

---

Energy
Funding is in compliance with the terms of the covenants in its financing documents, including the following requirements measured on the date of distribution:



The
debt service coverage ratio is determined by the amount of distributions received by the guarantors from the Big 4 projects during the relevant quarter divided by the debt service
(principal and interest) on Edison Mission Energy Funding's notes and bonds paid or due in the relevant quarter. During the 12 months ended March 31, 2003, the debt service coverage
ratio was 2.16 to 1. Although the credit ratings of Edison Mission Energy Funding's notes and bonds are below investment grade, this has no effect on the ability of the guarantors to make
distributions to EME.

CBK Project

EME holds a 50% interest in CBK Power Co Ltd. CBK Power operates under a 25-year build-rehabilitate-operate-transfer agreement with National
Power Corporation for the 755 MW Caliraya-Botocan-Kalayaan hydro electric complex, located in the Republic of the Philippines, which EME refers to as the CBK project. On April 23, 2003, the
President of the Republic of the Philippines signed into law the 2003 General Appropriations Bill which includes a provision that prohibits payments by agencies of the Philippine government to CBK
Power with respect to two of its units until
National Power Corporation submits a report based upon a review of "overpayments" to the CBK project, if any, and until the project documentation has been amended to provide for recovery by National
Power Corporation of any "overpayments." The assertion regarding "overpayment" stems from a supplemental agreement entered into during 1999 which modified the original build-rehabilitate-
operate-transfer agreement by adjusting the schedule for completion of two units of the CBK complex.

Under
the supplemental agreement, rehabilitation of existing Kalayaan Units 1 and 2 was brought forward because of National Power Corporation's concern about the possibility of
transformer failure and other risks affecting the reliability of these units. Under the original schedule, Kalayaan Units 1 and 2 were to be operated by CBK Power for operation and maintenance fees
only during the lengthy construction of new Kalayaan Units 3 and 4, and upon completion of these units, Kalayaan Units 1 and 2 were to be taken out of service for rehabilitation. Under the
build-rehabilitate-operate-transfer agreement, National Power Corporation is obligated to pay capacity recovery fees to CBK Power upon completion of the construction or rehabilitation of each unit, as
the case may be. EME understands the term "overpayment" as used in the Special Provision of the General Appropriations Act to refer to the payments of capital recovery fees for the Kalayaan Units 1
and 2 arising from the earlier than initially scheduled rehabilitation of these units. At the time EME made its investment in CBK Power, the decision to accelerate the work on Kalayaan Units 1 and 2
had been made and incorporated in the supplemental agreement, and all appropriate Philippine government approvals of the supplemental and other project agreements with National Power Corporation had
been obtained. Subsequently, some parties in the Philippines have contended that payments made to CBK Power as a result of the earlier than initially scheduled rehabilitation of Kalayaan Units 1 and 2
were unreasonable in comparison to the amount of additional work required to rehabilitate the units.

CBK
Power is currently considering legal options available to it to respond to the enactment of the Special Provision. Failure by National Power Corporation to pay and/or a failure by
the Philippine government to honor its commitments under the Government Undertaking signed in connection with the project to cause National Power Corporation to pay will constitute defaults under the
build-rehabilitate-operate-transfer agreement and the Government Undertaking, respectively. On April 28, 2003, CBK sent a notice of claim to the President of the Republic of the Philippines,
pursuant to the terms of the Government Undertaking. A default under the Government Undertaking will permit CBK

39

---

Power
to require the Philippine government to purchase the power plants subject to the build-rehabilitate-operate-transfer agreement for a price which will at least recover EME's investment in the
project. Prior to asserting these rights, however, CBK Power is required to engage in good faith negotiations with National Power Corporation in an attempt to resolve the situation. These discussions
have commenced but thus far have not resulted in a mutually acceptable resolution.

CBK
Power has advised its lenders of these developments and is discussing with them the ramifications under its credit agreements. Further, CBK Power has advised its lenders that
National Power Corporation is presently overdue in the payment of invoices totaling $11 million, a substantial portion of which is related to Kalayaan Units 1 and 2. Some of these events, if
not cured, are or may with the passage of time become events of default under CBK Power's credit agreements, which would permit
the lenders to demand payment in full of the project loans and to foreclose upon the assets of CBK Power. CBK Power intends to seek a waiver from the lenders of any existing defaults and any related
defaults as may occur while it considers its response to these developments and enters into negotiations with National Power Corporation. There is no assurance, however, that such a waiver will be
obtained or that, if not obtained, the lenders will not exercise their rights under the credit agreement.

As
of March 31, 2003, EME has invested $49 million in the CBK project and as of such date is committed to invest up to an additional $30 million. EME believes that
either on a negotiated basis or through the exercise of legal remedies it shall recover its entire investment. The indebtedness incurred by CBK Power is non-recourse to EME and, except for
EME's commitment to contribute up to an additional $30 million as equity, EME has no obligation with respect to CBK Power's indebtedness. Further, these events do not constitute a default under
any indebtedness incurred by EME or to which EME or any of its affiliates is subject.

Interest Coverage Ratio

During 2001, EME amended its organizational documents to include so-called "ring-fencing" provisions. These provisions require the
unanimous approval of EME's board of directors, including at least one independent director, before EME can do any of the following:



The
following details of EME's interest coverage ratio are provided as an aid to understanding the components of the computations that are set forth in EME's organizational documents.
This information is not intended to measure the financial performance of EME and, accordingly, should not be used in lieu of the financial information set forth in EME's consolidated financial
statements. The terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in EME's organizational documents and are not the same as would be determined in accordance
with generally accepted accounting principles.

40

---

The
following table sets forth the major components of the interest coverage ratio for the twelve months ended March 31, 2003 and the year ended December 31, 2002:

March 31,
2003

December 31,
2002(Unaudited)
(in millions)Funds Flow from Operations:Operating Cash Flow(1) from Consolidated Operating Projects(2):Illinois Plants(3)

$
304

$
294Homer City


95


51First Hydro


35


45Other consolidated operating projects


146


160Price risk management and trading


10


16Distributions from non-consolidated Big 4 projects


75


137Distributions from other non-consolidated operating projects


115


120Interest income


6


8Operating expenses


(134
)

(139
)Total funds flow from operations

$
652

$
692Interest Expense:From obligations to unrelated third parties

$
167

$
178From notes payable to Midwest Generation


114


115Total interest expense

$
281

$
293Interest Coverage Ratio


2.32


2.36


---

The
major factors affecting funds flow from operations during the twelve months ended March 31, 2003, compared to the year ended December 31, 2002, were:



Interest
expense decreased by $12 million for the twelve months ended March 31, 2003, compared to the year ended December 31, 2002 due to a lower average debt
balance.

EME's
interest coverage ratio for the twelve months ended March 31, 2003 was 2.32 to 1. Accordingly, EME is currently permitted to pay dividends of up to $32.5 million in
the second quarter of 2003 under the "ring-fencing" provisions of EME's certificate of incorporation and bylaws.

41

---

The above interest coverage ratio is not determined in accordance with generally accepted accounting principles as reflected in EME's Consolidated Statements of Cash Flows. Accordingly,
this ratio should not be considered in isolation or as a substitute for cash flows from operating activities or cash flow statement data set forth in EME's Consolidated Statement of Cash Flows. This
ratio does not measure the liquidity or ability of EME's subsidiaries to meet their debt service obligations. Furthermore, this ratio is not necessarily comparable to other similarly titled captions
of other companies due to differences in methods of calculations.

Edison Mission Energy Recourse Debt to Recourse Capital Ratio

Under the credit agreement governing its credit facility, EME has agreed to maintain a recourse debt to recourse capital ratio as shown in the table below.

|Financial Ratio                         |  | Covenant                    |  | Actual at
March 31, 2003 |  | Description                                                                                                                                                                              
|--------------------------------------- |  | --------------------------- |  | ------------------------ |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Recourse Debt to Recourse Capital Ratio |  | Less than or equal to 67.5% |  | 62.8%                    |  | Ratio of (a) senior recourse debt to (b) sum of (i) shareholder's equity per EME's balance sheet adjusted by comprehensive income after December 31, 1999, plus (ii) senior recourse
debt

Discussion of Recourse Debt to Recourse Capital Ratio

The recourse debt to recourse capital ratio of EME at March 31, 2003 and December 31, 2002 was calculated as follows:

March 31, 2003

December 31, 2002(Unaudited)
(in millions)Recourse Debt(1)Corporate Credit Facilities

$
220

$
140Senior Notes


1,600


1,600Guarantee of termination value of Powerton/Joliet operating leases


1,433


1,452Coal and Capex Facility


178


182Other


31


30Total Recourse Debt to EME

$
3,462

$
3,404Adjusted Shareholder's Equity(2)

$
2,049

$
2,066Recourse Capital(3)

$
5,511

$
5,470Recourse Debt to Recourse Capital Ratio


62.8
%

62.2
%


---

42

---

During
the three months ended March 31, 2003, the recourse debt to recourse capital ratio was slightly higher due to:



Subsidiary Financing Plans

The estimated capital and construction expenditures of EME's subsidiaries for the final three quarters of 2003 total $56 million. These expenditures are
planned to be financed by existing subsidiary credit agreements and cash generated from their operations, except with respect to the Homer City project. Under the Homer City sale-leaseback
agreements, EME has committed to provide funds for capital expenditures needed to complete the Homer City environmental improvement project. EME
expects to contribute $17 million in 2003 to fund the completion of this project, of which $7 million was contributed during the first quarter of 2003.

Edison Mission Midwest Holdings

EME's wholly owned subsidiary, Edison Mission Midwest Holdings, had long-term debt with the following maturities at March 31, 2003:

Amount

Due Date(in millions)$
911

December 2003808

December 2004$
1,719


In
addition, Edison Mission Midwest Holdings has a $150 million working capital facility (unused at March 31, 2003) which is scheduled to expire in December 2004. At
March 31, 2003, Edison Mission Midwest Holdings had cash and cash equivalents of $260 million, as well as $78 million deposited into a restricted cash account. Edison Mission
Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due in December 2003. Edison Mission Midwest Holdings plans to extend or refinance the
$911 million debt obligation prior to its expiration in December 2003. Completion of this extension or refinancing is subject to a number of uncertainties, including the ability of the
Illinois Plants to generate funds during the remainder of 2003 and the availability of new credit from financial institutions on acceptable terms in light of industry conditions. Accordingly, there is
no assurance that Edison Mission Midwest Holdings will be able to extend or refinance this debt when it becomes due or that the terms will not be substantially different from those under the current
credit facility.

Sunrise Project Financing

EME owns a 50% interest in Sunrise Power Company, which owns a natural gas-fired facility currently under construction in Kern County, California,
which EME refers to as the Sunrise project. The Sunrise project consists of two phases. Phase 1, a simple-cycle gas-fired facility (320 MW), was completed on June 27, 2001. Phase 2,
conversion to a combined-cycle gas-fired facility (bringing the capacity to a total of 560 MW), is currently scheduled to be completed in July 2003. Sunrise Power Company entered
into a long-term power purchase agreement with the California Department of Water Resources on June 25, 2001. The agreement was amended on December 31, 2002 as part of the
settlement of several matters between Sunrise Power Company and the State of California. The construction of the Sunrise project has been funded with equity contributions by its partners, including

43

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EME.
Sunrise Power Company has engaged a financial advisor to assist with obtaining project financing. Completion of project financing is subject to a number of uncertainties, including market
uncertainties and obtaining final environmental permits. EME believes that project financing will be obtained in 2003, although no assurance can be provided in this regard. If project financing is
completed by mid-2003, EME estimates a distribution of approximately $140 million to $150 million from the proceeds of such financing.

Intercompany Tax-Allocation Payments

EME 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 other subsidiaries of Edison International. These arrangements depend on Edison International continuing to own, directly or indirectly, at least 80% of the
voting power of the stock of EME and at least 80% of the value of such stock. The arrangements are subject to the terms of tax allocation and payment agreements among Edison International, Mission
Energy Holding Company, EME and other Edison International subsidiaries. The agreements to which EME is a party may be terminated by the immediate parent company at any time, by notice given before
the first day of the first year with respect to which the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year beginning
prior to the notice. EME has historically received tax-allocation payments related to domestic net operating losses incurred by EME. The right of EME to receive and the amount and timing
of tax-allocation payments are dependent on the inclusion of EME 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 EME, its subsidiaries, and other subsidiaries of Edison
International and specific procedures regarding allocation of state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison
International group generates sufficient taxable income in order to be able to utilize EME's tax losses in the consolidated income tax returns for Edison International and its subsidiaries. During the
first quarter of 2003, EME received $13 million in tax-allocation payments from Edison International. In the future, based on the application of the factors cited above,
EME may be obligated during periods it generates taxable income to make payments under the tax-allocation agreements.

Contractual Obligations

Chicago In-City Obligation

In April 2003, Midwest Generation and Commonwealth Edison amended their February 2003 settlement agreement which terminated Midwest Generation's
obligation to build additional gas-fired generation in the Chicago area. In accordance with the amendment, Midwest Generation paid Commonwealth Edison $9.8 million in exchange for
the termination of nine annual installment payments of $1.5 million beginning in 2004 and for the termination of the security interest of Commonwealth Edison in 125,000 barrels of oil at the
Collins Station.

MARKET RISK EXPOSURES

EME's primary market risk exposures are associated with the sale of electricity from and the procurement of fuel for its uncontracted generating plants. These
risks arise from fluctuations in electricity and fuel prices, emission and transmission rights, interest rates and foreign currency exchange rates. EME manages these risks in part by using derivative
financial instruments in accordance with established policies and procedures. See "GeneralCurrent Developments" and "Liquidity and Capital
ResourcesCredit Ratings" for a discussion of market developments and their impact on EME's credit and the credit of its counterparties.

44

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Commodity Price Risk

EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored to ensure compliance
with EME's risk management policies. Policies are in place which define risk tolerances for each EME regional business unit. Procedures exist which allow for monitoring of all commitments and
positions with regular reviews by a risk management committee. EME performs a "value at risk" analysis in its daily business to measure,
monitor and control its overall market risk exposure. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the drivers of the
risk. 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, as well as stop loss limits and counterparty credit exposure
limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

Electric
power generated at EME's domestic merchant plants is generally sold under bilateral arrangements with utilities and power marketers under short-term transactions
with terms of two years or less or, in the case of the Homer City facilities, to the PJM and/or the New York Independent System Operator (NYISO) as well as utilities and power marketers. As discussed
further below, beginning in 2003, EME is selling a significant portion of the power generated from its Illinois Plants into wholesale energy markets. In order to provide more predictable earnings and
cash flow, EME may hedge a portion of the electric output of its merchant plants, the output of which is not committed to be sold under long-term contracts. When appropriate, EME manages
the spread between electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives. There is no assurance that contracts to hedge changes
in market prices will be effective.

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



A
discussion of each market area is set forth below by region.

45

---

Americas

Illinois Plants

Electric power generated at the Illinois Plants is sold under three power purchase agreements between EME's wholly owned subsidiary, Midwest Generation, and
Exelon Generation Company, under which Exelon Generation purchases capacity and has the right to purchase energy generated by the Illinois Plants. The agreements, which began on December 15,
1999 and expire in December 2004, provide for capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the plants under contract and an energy payment for the
electricity produced by these plants and taken by Exelon Generation. The capacity payments provide the revenue for fixed charges, and the energy payments compensate the Illinois Plants for variable
costs of production.

Under
each of the power purchase agreements, Exelon Generation, upon notice by a specified date, has the option to terminate each agreement with respect to all or a portion of the units
subject to it, as described below. As a result of notices given in 2002, Exelon Generation released 4,548 MW of Midwest Generation's generating capacity from the power purchase agreements, thus
increasing Midwest Generation's reliance on sales into the wholesale markets. As a result, 4,739 MW remain subject to power purchase agreements with Exelon Generation in 2003.

Under
the power purchase agreement related to Midwest Generation's coal-fired generation units, Exelon Generation continues to have a similar option, exercisable not later
than 180 days prior to January 1, 2004, to retain or release for 2004 all or a portion of the 1,265 MW of option coal units retained for 2003. Exelon Generation remains committed to
purchase the capacity of committed units having 1,696 MW of capacity for both 2003 and 2004.

Under
the power purchase agreements related to Midwest Generation's Collins Station and peaking units, Exelon Generation continues to have a similar option to terminate, exercisable not
later than 90 days prior to January 1, 2004, the power purchase agreements for 2004 with respect to all or a portion of the 1,084 MW from the Collins Station, and 694 MW from the peaking
units, that were retained for 2003.

The
energy and capacity from any units which are not subject to one of the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity, to be
negotiated with customers through a combination of bilateral agreements, forward energy sales and spot market sales. These arrangements generally have a term of two years or less. Thus, EME will be
subject to market risks related to the price of energy and capacity described above. EME expects that capacity prices for merchant energy sales will, in the near term, be negligible in comparison to
those Midwest Generation currently receives under its existing agreements with Exelon Generation (with the possibility of minimal revenues due to the current oversupply conditions in this
marketplace). EME further expects that the lower revenues resulting from this difference will be offset in part by energy prices, which EME believes will, in the near term, be higher for merchant
energy sales than those Midwest Generation currently receives under its existing agreements, as indicated below in the table of forward-looking prices. EME intends to manage this price risk, in part,
by accessing both the wholesale customer and over-the-counter markets described below as well as using derivative financial instruments in accordance with established policies
and procedures.

During
2003, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois Plants are expected to be "wholesale customer" and
"over-the-counter." The most liquid over-the-counter markets in the Midwest region are sales into the control area of Cinergy, referred to as "Into
Cinergy," and, to a lesser extent, sales into the control area of Commonwealth Edison, referred to as "Into ComEd" (due to geographic proximity, "Into ComEd" has been the primary market for Midwest
Generation). "Into Cinergy" and "Into ComEd" are bilateral markets for the sale or purchase of electrical energy for future delivery. Performance of transactions in these markets is subject to
contracts that generally provide for liquidated damages supported by a variety of credit requirements, which may include independent credit assessment, parental guarantees, letters of credit and cash
margining arrangements.

46

---

The following table depicts the historical average market prices for energy per megawatt-hour "Into ComEd" and "Into Cinergy" for the first three months of 2003:

|                  |  | Into ComEd* |       | Into Cinergy*
|----------------- |  | ----------- | ----- | -------------
|
|
|January           |  | $           | 37.06 |              
|February          |  |             | 51.71 |              
|March             |  |             | 47.96 |              
|                  |  |             |       |              
|Quarterly Average |  | $           | 45.58 |              
|                  |  |             |       |              

---

The
following table sets forth forward market prices for energy per megawatt-hour as quoted for sales "Into ComEd" and "Into Cinergy" at March 31, 2003. These forward
prices will continue to fluctuate as a result of a number of factors, including gas prices, electricity demand, which is also affected by economic growth, and the amount of existing and planned power
plant capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward market prices.

|                         |           | Into ComEd* |       | Into Cinergy*
|------------------------ | --------- | ----------- | ----- | -------------
|
|
|2003                     |           |             |       |              
|                         | April     |             | $     | 36.00        
|                         | May       |             |       | 33.81        
|                         | June      |             |       | 35.50        
|                         | July      |             |       | 45.18        
|                         | August    |             |       | 44.18        
|                         | September |             |       | 31.43        
|                         | October   |             |       | 28.50        
|                         | November  |             |       | 29.50        
|                         | December  |             |       | 30.50        
|2004 Calendar "strip"(2) |           |             | 34.43 |              

---

Midwest
Generation intends to hedge a portion of its merchant portfolio risk through its marketing affiliate. To the extent it does not do so, the unhedged portion will be subject to the
risks and benefits of spot market price movements. The extent to which Midwest Generation will hedge its market price risk through forward over-the-counter sales depends on
several factors. First, Midwest Generation will evaluate over-the-counter market prices to determine whether sales at forward market

47

---

prices
are sufficiently attractive compared to assuming the risk associated with spot market sales. Second, Midwest Generation's ability to enter into hedging transactions will depend upon its and its
marketing affiliate's credit capacity and upon the over-the-counter forward sales markets' having sufficient liquidity to enable Midwest Generation to identify counterparties
who are able and willing to enter into hedging transactions with it. Due to factors beyond Midwest Generation's control, market liquidity decreased significantly during 2002 and a number of formerly
significant trading parties have completely withdrawn from the market or substantially reduced their trading activities. See "Credit Risk," below.

In
addition to the prevailing market prices, Midwest Generation's ability to derive profits from the sale of electricity from the released units will be affected by the cost of
production, including costs incurred to comply with environmental regulations. The costs of production of the released units vary and, accordingly, depending on market conditions, the amount of
generation that will be sold from the released units is expected to vary from unit to unit. In this regard, Midwest Generation suspended operations of Will County Units 1 and 2 and Collins Station
Units 4 and 5 at the end of 2002 pending improvement in market conditions. If market conditions were to be depressed for an extended period of time, Midwest Generation would need to consider
decommissioning these units, which would result in a charge against income.

In
addition to the price risks described previously, there are risks with respect to the availability and cost of transmission required to market the power produced by the units not
under contract with Exelon Generation. Currently, transmission must be obtained from Commonwealth Edison under its open-access tariff filed with the Federal Energy Regulatory Commission.
Recently, however, Commonwealth Edison and PJM issued a joint press release announcing the integration of Commonwealth Edison into PJM, beginning June 1, 2003, with a goal of being "fully
integrated" by October 2003. In response to this announcement, EME and a number of other affected parties have filed with the Commission contesting the integration of Commonwealth Edison into
PJM on a so-called "islanded" basis. See "Regulatory Matters." EME is unable to predict the manner in which the Commission will react or, if such integration is permitted, the
effect of any final integration configuration on the markets into which Midwest Generation sells its power.

Midwest
Generation's ability to transmit energy to counterparty delivery points to consummate spot sales and hedging transactions may also be affected by transmission service limitations
and constraints and new standard market design proposals proposed by and currently pending before the Federal Energy Regulatory Commission. Although the Federal Energy Regulatory Commission and the
relevant
industry participants are working to minimize such issues, Midwest Generation cannot determine how quickly or how effectively such issues will be resolved.

Homer City Facilities

Electric power generated at the Homer City facilities is sold under bilateral arrangements with domestic utilities and power marketers pursuant to transactions
with terms of two years or less, or to the PJM or the NYISO. These pools have short-term markets, which establish an hourly clearing price. The Homer City facilities are situated in the
PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and NYISO markets. The Homer City facilities can also transmit power to the Midwestern
United States.

48

---

The
following table depicts the average market prices per megawatt-hour in PJM during the first quarters of 2003 and 2002:

24-Hour PJM
Historical Energy Prices*2003

2002January

$
36.56

$
20.52February


46.13


20.62March


46.85


24.27Quarterly Average

$
43.18

$
21.80


---

As
shown on the above table, the average historical market prices at the Homer City busbar (delivery point) during the first three months of 2003 were significantly higher than the
average historical market prices during the first three months of 2002. Forward market prices in PJM fluctuate as a result of a number of factors, including natural gas prices, transmission
congestion, changes in market rules, electricity demand which is affected by weather and economic growth, and the amount of existing and planned power plant capacity. The actual spot prices for
electricity delivered into these markets may vary materially from the forward market prices.

Sales
made in the real-time or day-ahead market receive the actual spot prices at the Homer City busbar. In order to mitigate price risk from changes in spot
prices at the Homer City busbar, EME may enter into forward contracts with counterparties for forecasted generation in future periods. Currently, there is not a liquid market for entering into forward
contracts at the Homer City busbar. A liquid market does exist for delivery to a collection of delivery points known as PJM West Hub, which EME's price risk management activities use to enter into
forward contracts. EME's revenues with respect to such forward contracts include:



Under
the PJM market design, locational marginal pricing (sometimes referred to as LMP) has the effect of reducing prices at those delivery points affected by transmission congestion and
raising prices at points which are free of the congestion. During the past 12 months, an increase in transmission congestion between the Homer City facilities and delivery points east has
resulted in prices at the Homer City facilities being lower than those at PJM West Hub, which is east of the Homer City facilities. Thus, while forward prices at PJM West Hub have historically been
higher than the prices at the Homer City busbar by less than 5%, increased congestion during the last 12 months between the Homer City facilities and points east has resulted in prices at PJM
West Hub being on average 11% higher than those at the Homer City busbar.

By
entering into forward contracts using the PJM West Hub as the delivery point, EME is exposed to "basis risk", which occurs when forward contracts are executed on a different basis (in
this case PJM West Hub) than the actual point of delivery (Homer City busbar). In order to mitigate basis risk resulting from forward contracts using PJM West Hub as the delivery point, EME has
participated in purchasing firm transmission rights in PJM, and may continue to do so in the future. A firm transmission right provides the holder with a financial instrument to receive actual spot
prices at one point of delivery and pay spot prices at another point of delivery. Accordingly, EME's price risk

49

---

management
activities include using firm transmission rights alone or in combination with forward contracts to manage changes in prices within the PJM market.

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, 2003:

24-Hour PJM West
Forward Energy Prices*2003April

$
42.67May


41.43June


44.10July


53.24August


49.55September


39.43October


36.28November


34.86December


36.602004 Calendar "strip"(1)


34.97


---

The
ability of EME's subsidiary, EME Homer City, to make payments under the long-term lease entered into as part of the sale-leaseback transaction discussed under
"Off-Balance Sheet TransactionsSale-Leaseback Transactions," included in Item 7 of EME's annual report on Form 10-K for the year
ended December 31, 2002, depends on revenues generated by the Homer City facilities, which depend in part on the market conditions for the sale of capacity and energy. These market conditions
are beyond EME's control.

Europe

United Kingdom

The First Hydro plant sells electrical energy and capacity through bilateral contracts of varying terms in the England and Wales wholesale electricity market.

The
electricity trading arrangements introduced in March 2001 provide, among other things, for the establishment of a range of voluntary short-term power exchanges and
brokered markets operating from a year or more in advance to 1 hour prior to the delivery or receipt of power. In the final hour after the notification of all contracts, the system operator can
accept bids and offers in the Balancing Mechanism to balance generation and demand and resolve any transmission constraints. There is a mandatory settlement process for recovering imbalances between
contracted and metered volumes with strong incentives for being in balance, and a Balancing and Settlement Code Panel to oversee governance of the Balancing Mechanism. The system operator can also
purchase system reserve and response services to maintain the quality of the electrical supply directly from generators (generally referred to as "ancillary services"). Ancillary services contracts
typically run for up to a year and can consist of both fixed amounts and variable amounts represented by prices for services that are only paid for when actually called upon by the grid operator. A
key feature of the trading arrangements is the requirement for firm physical delivery, which means that a generator must deliver, and a consumer

50

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must
take delivery of, its net contracted positions or pay for any energy imbalance at the imbalance prices calculated by the system operator based on the prices of bids and offers accepted in the
Balancing Mechanism. This provides an incentive for parties to contract in advance and for the development of forwards and futures markets. Under these arrangements, there has been an increased demand
for credit support, including parent company guarantees or letters of credit.

The
wholesale price of electricity has decreased significantly in recent years. The reduction has been driven principally by surplus generating capacity and increased competition. In
addition, First Hydro was adversely affected in the second half of 2001 by a fall in the differential of the peak day time energy price compared to the cost of purchasing power at night time to pump
water back to the top reservoir. This too was a reflection both of excess generating capacity on the system as a whole. During 2002 and the first quarter of 2003, there was further downward pressure
on wholesale prices but some recovery in the peak/off peak differentials during the winter period.

Despite
the difficult market conditions, First Hydro has continued to meet the interest coverage ratios specified in its bond financing documents, and to meet its half yearly interest
payments without recourse to the project's debt service reserve. EME believes that if market and trading conditions experienced in 2002 are sustained, First Hydro will continue to be compliant with
the requirements of its bond financing documents. This compliance is, however, subject to market conditions for electric energy and ancillary services, which are beyond EME's control.

Asia Pacific

Australia

The Loy Yang B plant and the Valley Power Peaker project sell electrical energy through a centralized electricity pool, which provides for a system of generator
bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and
administrator of the pool, determines a system marginal price each half-hour. To mitigate exposure to price volatility of the electricity traded into the pool, the Loy Yang B plant and the
Valley Power Peaker project have entered into a number of financial hedges. The State Hedge agreement with the State Electricity Commission of Victoria is a long-term contractual
arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State Government of Victoria, Australia guarantees the State Electricity Commission of
Victoria's obligations under the State Hedge. From January 2003 to July 2014, approximately 77% of the Loy Yang B plant output sold is hedged under the State Hedge. From
August 2014 to October 2016, approximately 56% of the Loy Yang B plant output sold is hedged under the State Hedge. Additionally, the Loy Yang B plant and the Valley Power Peaker project
have entered into a number of derivative contracts to mitigate further against price volatility inherent in the electricity pool. These contracts consist of fixed forward electricity contracts and/or
cap contracts that expire on various dates through December 31, 2006.

New Zealand

Contact Energy generates about a quarter of New Zealand's electricity and is the largest retailer of natural gas and electricity in New Zealand. A substantial
portion of Contact Energy's generation output is matched with the demand of its retail electricity customers or sold through forward contracts with other wholesale electricity counterparties. The
forward contracts and/or option contracts have varying terms that expire on various dates through June 30, 2010, although the majority of the forward contracts are short term (less than two
years).

The
New Zealand Government released a Government Policy Statement in December 2001, which called for the industry to rationalize the three existing industry codes, form a
single governance structure and address transmission investment and pricing issues.

51

---

During
2001, an amendment to the Electricity Act of 1992 was passed that laid out the form that regulation would take if the industry does not heed the government's call. A draft single
governance code was presented to the New Zealand Commerce Commission for approval early in 2002. In October 2002, the Commerce Commission approved the new arrangements in the form of a rulebook
for the self-governance of the electricity sector, with some conditions attached. The market participants are currently voting to determine whether the rulebook will be adopted. It is
currently anticipated that the vote will not succeed and that a government-imposed body will be
formed. The New Zealand Government is therefore currently progressing with plans for a Crown Electricity Governance Board, which is likely to be substantially based on the single rulebook created
following the earlier Government Policy Statement. Under this model, the Governance Board will be responsible for acting on government policy and will implement measures approved by regulation.

While
these arrangements have been progressing, several events in the months leading to the winter of 2003 in New Zealand have raised concerns about the security of supply in the
country. Wholesale electricity prices have risen in response to dry hydro conditions, higher-than-expected demand, and anticipated restrictions on the availability of thermal
fuel. Further, there are concerns that new investment in generation has not been forthcoming with the risk that similar shortages may arise in subsequent years. In March 2003, the Government
responded to these conditions by suggesting that significant changes may be required to the electricity market to avoid the risk of insufficient supply in the future. In early May 2003, the
Government issued a statement suggesting that the market would be retained, but that a mechanism would be introduced to operate alongside the market to ensure that there is sufficient standby
generation to meet potential shortages in the future. Fuller details of this mechanism are expected to be announced towards the end of May 2003 or in June 2003.

Credit Risks

In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and financial institutions. Due to
factors beyond EME's control, market liquidity has decreased significantly since the beginning of 2002, and a number of formerly significant trading parties have completely withdrawn from the market
or substantially reduced their trading activities. The reduction in the credit quality of traditional trading parties increases EME's credit risk. In addition, the decrease in market liquidity may
require EME to rely more heavily on wholesale electricity sales to wholesale customer markets, which may also increase EME's credit risk. While various industry groups and regulatory agencies have
taken steps to address market liquidity, transparency and credit issues, there is no assurance as to when, or how effectively, such efforts will restore market confidence. In the event a counterparty
were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with reselling the contracted product at a lower 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 such counterparty defaulted.

To
manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME would record if its counterparties failed to perform
pursuant to the terms of their contractual obligations. EME has established controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever
possible to mitigate its exposure to counterparty risk. EME may require counterparties to pledge collateral when deemed necessary. EME tries to manage the credit in its 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. The credit quality of EME's counterparties is reviewed regularly by EME's risk management committee. In
addition to continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower

52

---

credit
exposure. Despite this, there can be no assurance that EME's actions to mitigate risk will be wholly successful or that collateral pledged will be adequate.

EME
measures credit risk exposure from counterparties of its merchant energy activities by the sum of: (i) 60 days of accounts receivable, (ii) current fair value of
open positions, and (iii) a credit value at risk. 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. The credit ratings of EME's counterparties were as follows:

S&P Credit Rating

March 31, 2003(in millions)A or higher

$
31A-


10BBB+


67BBB


56BBB-


1Total

$
165


Exelon
Generation accounted for 19% and 30% of EME's consolidated operating revenues for the first quarters of 2003 and 2002, respectively. The percentage is less in 2003 because a
smaller number of plants are subject to contracts with Exelon Generation. See "Market Risk ExposuresAmericasIllinois Plants." Any failure of Exelon Generation to make
payments to Midwest Generation under the power purchase agreements could result in a shortfall of cash available for Midwest Generation to meet its obligations. A default by Midwest Generation in
meeting its obligations could in turn have a material adverse effect on EME.

EME's
contracted power plants and the 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 affect on the operations of such power plant.

Interest Rate Risk

Interest rate changes affect the cost of capital needed to operate EME's projects and the lease costs under the Collins Station lease. EME has mitigated 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. Interest expense included $9 million and $10 million of additional interest expense for the three months ended March 31, 2003 and 2002, respectively, as a result of
interest rate hedging mechanisms. EME has entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt.

EME
had short-term obligations of $127 million at March 31, 2003, consisting of borrowings under EME's corporate credit facility and promissory notes related to
Contact Energy. The fair values of these obligations approximated their carrying values at March 31, 2003, and would not have been materially affected by changes in market interest rates. The
fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's total long-term obligations (including current
portion) was $5.6 billion at March 31, 2003, compared to the carrying value of $6.3 billion.

53

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Foreign Exchange Rate Risk

Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of EME's equity contributions to, and distributions
from, its international projects. At times, EME has hedged a portion of its current exposure to fluctuations in foreign exchange rates through financial derivatives, offsetting obligations denominated
in foreign currencies, and indexing underlying project agreements to U.S. dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, EME has used
statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. EME cannot provide assurances, however, that fluctuations in exchange rates will be
fully offset by hedges or that currency movements and the relationship between certain macroeconomic variables will behave in a manner that is consistent with historical or forecasted relationships.

The
First Hydro plant in the U.K. and the plants in Australia have been financed in their local currencies, pounds sterling and Australian dollars, respectively, thus hedging the
majority of their acquisition costs against foreign exchange fluctuations. Furthermore, EME has evaluated the return on the remaining equity portion of these investments with regard to the likelihood
of various foreign exchange scenarios. These analyses use market-derived volatilities, statistical correlations between specified variables, and long-term forecasts to predict ranges of
expected returns.

During
the first three months of 2003, foreign currencies in Australia and New Zealand increased in value compared to the U.S. dollar by 7% and 5%, respectively (determined by the change
in the exchange rates from December 31, 2002 to March 31, 2003). The increase in value of these currencies was the primary reason for the foreign currency translation gain of
$21 million during the first three months of 2003.

Contact
Energy enters into foreign currency forward exchange contracts to hedge identifiable foreign currency commitments associated with transactions in the ordinary course of business.
The contracts are primarily in Australian and U.S. dollars with varying maturities through April 2004. At March 31, 2003, the outstanding notional amount of the contracts totaled
$16 million and the fair value of the contracts totaled $(120,000).

In
addition, Contact Energy enters into cross currency interest rate swap contracts in the ordinary course of business. These cross currency swap contracts involve swapping fixed and
floating-rate U.S. and Australian dollar loans into floating-rate New Zealand dollar loans with varying maturities through April 2018.

EME
will continue to monitor its foreign exchange exposure and analyze the effectiveness and efficiency of hedging strategies in the future.

Non-Trading Derivative Financial Instruments

The following table summarizes the fair values for outstanding derivative financial instruments used for purposes other than trading by risk category and
instrument type (in millions):

March 31, 2003

December 31, 2002(Unaudited)Derivatives:Interest rate:Interest rate swap/cap agreements

$
(51
)
$
(48
)Interest rate options


(2
)

(2
)Commodity price:Electricity


(129
)

(100
)Cross currency interest rate swaps


(15
)

(2
)


54

---

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, the valuation method and the related fair value of EME's commodity price risk management assets and liabilities (as of March 31, 2003)
(in millions):

|                                                   |  | Total Fair
Value |      | Maturity
<1 year |   | Maturity
1 to 3
years |   | Maturity
4 to 5
years |    | Maturity
>5 years |  
|-------------------------------------------------- |  | ---------------- | ---- | ---------------- | - | --------------------- | - | --------------------- | -- | ----------------- | -
|
|Prices actively quoted                             |  | $                | (46  | )                | $ | (46                   | ) | $                     |   |                   | $
|Prices based on models and other valuation methods |  |                  | (83  | )                |   | 8                     |   |                       | (2 | )                 |  
|                                                   |  |                  |      |                  |   |                       |   |                       |    |                   |  
|Total                                              |  | $                | (129 | )                | $ | (38                   | ) | $                     | (2 | )                 | $
|                                                   |  |                  |      |                  |   |                       |   |                       |    |                   |  

The
fair value of the electricity rate swap agreements (included under commodity price-electricity) entered into by the Loy Yang B plant and the First Hydro plant has been estimated by
discounting the future net cash flows resulting from the difference between the average aggregate contract price per
MW and a forecasted market price per MW multiplied by the number of MW remaining to be sold under the contract.

Energy Trading Derivative Financial Instruments

EME's risk management and trading operations are conducted by its subsidiary, Edison Mission Marketing & Trading. As a result of a number of industry and
credit related factors, Edison Mission Marketing & Trading has minimized its price risk management activities and its trading activities with third parties not related to EME's power plants or
investments in energy projects. To the extent Edison Mission Marketing & Trading engages in trading activities, Edison Mission Marketing & Trading seeks to manage price risk and to
create stability of future income by selling electricity in the forward markets and, to a lesser degree, to generate profit from price volatility of electricity and fuels by buying and selling these
commodities in wholesale markets. EME generally balances forward sales and purchase contracts and manages its exposure through a value at risk analysis as described under "Commodity Price
Risk."

The
fair value of the commodity financial instruments related to energy trading activities as of March 31, 2003 and December 31, 2002, are set forth below (in millions):

|            |  | March 31, 2003 |     | December 31, 2002
|----------- |  | -------------- | --- | -----------------
|
|
|Electricity |  | $              | 143 |                  
|Other       |  |                | (1  | )                
|            |  |                |     |                  
|Total       |  | $              | 142 |                  
|            |  |                |     |                  

The
change in the fair value of trading contracts for the quarter ended March 31, 2003, was as follows (in millions):

|Fair value of trading contracts at December 31, 2002          |  | $ | 92  |  
|------------------------------------------------------------- |  | - | --- | -
|Net gains from energy trading activities                      |  |   | 15  |  
|Amount realized from energy trading activities                |  |   | (11 | )
|                                                              |  |   |    
|Fair value of trading contracts at March 31, 2003 (unaudited) |  | $ | 96  |  
|                                                              |  |   |    

55

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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, 2003) (in millions):

|                                                   |  | Total Fair
Value |    | Maturity
<1 year |   | Maturity
1 to 3
years |   | Maturity
4 to 5
years |   | Maturity
>5 years
|-------------------------------------------------- |  | ---------------- | -- | ---------------- | - | --------------------- | - | --------------------- | - | -----------------
|
|Prices actively quoted                             |  | $                | 3  |                  | $ | 3                     |   | $                     |  |                  
|Prices based on models and other valuation methods |  |                  | 93 |                  |   | (3                    | ) |                       | 4 |                  
|                                                   |  |                  |    |                  |   |                       |   |                       |   |                  
|Total                                              |  | $                | 96 |                  | $ |                      |   | $                     | 4 |                  
|                                                   |  |                  |    |                  |   |                       |   |                       |   |                  

Regulatory Matters

For a discussion of EME's regulatory matters, refer to "Regulatory Matters" on page 20 of EME's annual report on Form 10-K for the year ended
December 31, 2002 and the notes to the Consolidated Financial Statements set forth therein. There have been no significant developments with regard to regulatory matters that affect disclosures
presented in the annual report, except as follows:

Currently,
power produced by the Illinois Plants not under contract with Exelon Generation is sold using transmission which must be obtained from Commonwealth Edison under its
open-access tariff filed with the Federal Energy Regulatory Commission. In 2002, Commonwealth Edison applied to the Commission for approval to join PJM in conjunction with
American Electric Power, thereby creating an enlarged, contiguous regional transmission organization encompassing a broad regional market. Approval of this application was granted by the Commission on
April 1, 2003. Concurrently, the ability of American Electric Power to join PJM has been brought into question by the enactment of legislation in Virginia requiring the approval of Virginia
state authorities for any transfer of control from American Electric Power to PJM of American Electric Power transmission assets located in Virginia. On April 16, 2003, Commonwealth Edison and
PJM issued a joint press release stating that the integration of Commonwealth Edison into PJM would proceed separately from that of American Electric Power, notwithstanding the absence of a direct
transmission link owned by Commonwealth Edison between its service territory and the existing PJM. In response to this announcement, EME and other affected parties have filed with the Federal Energy
Regulatory Commission for clarification or rehearing of its April 1, 2003 order, and essentially contesting the appropriateness of Commonwealth Edison joining PJM on an "islanded" basis. Given
the stated intentions of Commonwealth Edison and PJM to proceed with integration beginning June 1, 2003, EME has requested expedited treatment of its request for clarification or rehearing. See
also, "Market Risk ExposuresCommodity Price RiskAmericasIllinois Plants."

Off-Balance Sheet Transactions

For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" on page 80 of EME's annual report on
Form 10-K for the year ended December 31, 2002.

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Environmental Matters and Regulations

For a discussion of EME's environmental matters, refer to "Environmental Matters and Regulations" on page 100 of EME's annual report on
Form 10-K for the year ended December 31, 2002 and the notes to the Consolidated Financial Statements set forth therein. There have been no significant developments with
regard to environmental matters that affect disclosures presented in the annual report.

Critical Accounting Policies and Estimates

For a discussion of EME's critical accounting policies and estimates, refer to "Critical Accounting Policies and Estimates" on page 51 of EME's annual report on
Form 10-K for the year ended December 31, 2002.

New Accounting Standards

Statement of Financial Accounting Standards No. 143

Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS
No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. As of
January 1, 2003, EME recorded $9 million, after tax, decrease to net income as the cumulative effect of adoption of SFAS No. 143.

Statement of Financial Accounting Standards No. 146

Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities." SFAS No. 146 requires that liabilities for costs associated with exit or disposal activities initiated after December 31, 2002 be recognized when incurred, rather than at
the date of a commitment to an exit or disposal plan. The adoption of this standard had no impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards Interpretation No. 45

In November 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about
its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified
after December 31, 2002. The adoption of this standard had no impact on EME's financial statements. See "Commitments and ContingenciesGuarantees and Indemnities."

Statement of Financial Accounting Standards Interpretation No. 46

In January 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation
of Variable Interest Entities" (FIN 46). This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements,"

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addresses
consolidation by business enterprises of variable interest entities. The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for,
entities over which control is achieved through means other than voting rights; such entities are known as variable-interest entities. This interpretation applies to variable interest entities created
after January 31, 2003, and applies to variable interest entities in which EME holds a variable interest that it acquired before February 1, 2003, beginning July 1, 2003.

Under
FIN 46, an enterprise that will (1) absorb a majority of a variable interest entity's expected losses (if they occur), (2) receive a majority of a variable interest
entity's expected residual returns (if they occur), or (3) both of the above, must consolidate the variable interest entity. The enterprise that consolidates the variable interest entity is
called the primary beneficiary. EME believes it is reasonably possible that one or more of its investments in unconsolidated affiliates will be a variable interest entity. Accordingly, EME is in the
process of making this determination, and for investments in unconsolidated affiliates which are variable interest entities, a further determination will be made if EME is the primary beneficiary.

EME
has concluded that it is the primary beneficiary of Brooklyn Navy Yard Cogeneration Partners L.P. since it is at risk with respect to a majority of its losses and is entitled to
receive a majority of its residual returns. Accordingly, EME will consolidate Brooklyn Navy Yard Cogeneration Partners L.P. effective July 1, 2003. In accordance with the transition provisions
of FIN 46, the consolidation of Brooklyn Navy Yard Cogeneration Partners L.P. will be based on the historical cost of the assets, liabilities and non-controlling interest which would have
been carried by EME effective when EME became the primary beneficiary. This means that EME will consolidate the assets and liabilities of Brooklyn Navy Yard Cogeneration Partners L.P. using the
June 30, 2003 balance sheet and eliminate intercompany balances. EME expects the consolidation of this entity to increase total assets by approximately $364 million and total liabilities
by approximately $435 million. Furthermore, EME expects to record a loss of approximately $71 million as a cumulative change of accounting as a result of consolidating this variable
interest entity. This loss is primarily due to cumulative losses allocated to the other 50% partner in excess of equity contributions recorded.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 83 of EME's annual report on Form 10-K for the
year ended December 31, 2002. Refer to "Market Risk Exposures" in Item 2 for an update to that disclosure.

ITEM 4. CONTROLS AND PROCEDURES

Under the Sarbanes-Oxley Act of 2002 and implementing rules and regulations adopted by the Securities and Exchange Commission (SEC), EME must maintain disclosure
controls and procedures. The term "disclosure controls and procedures" is defined in the SEC's regulations to mean, as applied to EME, controls and other procedures that are designed to ensure that
information required to be disclosed by EME in reports filed with the SEC is recorded, processed, summarized, and reported, within the time frames specified in the SEC's rules and forms. Disclosure
controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by EME in its SEC reports is accumulated and communicated to
EME's management, including its Chief Executive Officer and its Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. The SEC's regulations also require EME to carry
out evaluations, under the supervision and with the participation of EME's management, including its Chief Executive Officer and its Chief Financial Officer, of the effectiveness of the design and
operation of EME's disclosure controls and procedures. These evaluations must be carried out within the 90-day period prior to the filing date of certain reports, including this quarterly
report on Form 10-Q.

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The
Chief Executive Officer and the Chief Financial Officer of EME have evaluated the effectiveness of the design and operation of EME's disclosure controls and procedures as of
May 8, 2003. They have concluded that those disclosure controls and procedures, as of the evaluation date, were effective in ensuring that information required to be disclosed by EME in its
reports filed with the SEC was (1) accumulated and communicated to EME's management, as appropriate to allow timely decisions regarding disclosure, and (2) recorded, processed,
summarized, and reported within the time frames specified in the SEC's rules and forms.

The
Chief Executive Officer and the Chief Financial Officer of EME also have concluded that there were no significant changes in EME's internal controls or in other factors that could
significantly affect those controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

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PART IIOTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)   Exhibits

Exhibit No.

Description10.1

Terms of 2003 stock option and performance share awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter
ended March 31, 2003 (File No. 1-9936).99.1

Homer City Facilities Funds Flow From Operations for the twelve months ended March 31, 2003.99.2

Illinois Plants Funds Flow From Operations for the twelve months ended March 31, 2003.99.3

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


(b)   Reports on Form 8-K

The registrant filed the following reports on Form 8-K during the quarter ended March 31, 2003.

Date of Report

Date Filed

Item ReportedDecember 20, 2002

January 8, 2003

5January 17, 2003

February 25, 2003

5


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SIGNATURES

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 MISSION ENERGY(REGISTRANT)
| |  | ---------------------------------
| |  | By:                              
| |  | Date:                            

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CERTIFICATION

I,
Thomas R. McDaniel, certify that:

|Date: May 14, 2003 |  | /s/ Thomas R. McDanielThomas R. McDaniel President and Chief Executive Officer
|------------------ |  | ------------------------------------------------------------------------------

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CERTIFICATION

I,
Kevin M. Smith, certify that:

|Date: May 14, 2003 |  | /s/ Kevin M. SmithKevin M. Smith Senior Vice President, Chief Financial
Officer and Treasurer
|------------------ |  | ---------------------------------------------------------------------------------------------

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