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UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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Form 10-Q

(Mark one)

|ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ---------------------------------------------------------------------------------------

For the Quarterly Period Ended September 30, 2002

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

Number
of shares outstanding of the registrant's Common Stock as of November 11, 2002: 100 shares (all shares held by an affiliate of the registrant).

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TABLE OF CONTENTS

|Item                         |  |                                                                                       |  | Page
|---------------------------- |  | ------------------------------------------------------------------------------------- |  | ----
|PART IFinancial Information
|1.                           |  | Financial Statements                                                                  |  | 1   
|2.                           |  | Management's Discussion and Analysis of Results of Operations and Financial Condition |  | 26  
|3.                           |  | Quantitative and Qualitative Disclosures About Market Risk                            |  | 73  
|4.                           |  | Controls and Procedures                                                               |  | 73  
|PART IIOther Information   
|1.                           |  | Legal Proceedings                                                                     |  | 74  
|6.                           |  | Exhibits and Reports on Form 8-K                                                      |  | 76  
|                             |  | Signatures                                                                            |  | 77  
|                             |  | Certifications                                                                        |  | 78  

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PART IFINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

|                                       |                                                                                       | Three Months Ended
September 30, |         | Nine Months Ended
September 30, |          
|-------------------------------------- | ------------------------------------------------------------------------------------- | -------------------------------- | ------- | ------------------------------- | ---------
|
|
|Operating Revenues                     |                                                                                       |                                  |         |                                 |          
|                                       | Electric revenues                                                                     |                                  | $       | 960,677                         |          
|                                       | Equity in income from energy projects                                                 |                                  |         | 112,313                         |          
|                                       | Equity in income from oil and gas investments                                         |                                  |         | 7,351                           |          
|                                       | Net gains from price risk management and energy trading                               |                                  |         | 4,676                           |          
|                                       | Operation and maintenance services                                                    |                                  |         | 9,316                           |          
|                                       |                                                                                       |                                  |         |                                 |          
|                                       |                                                                                       | Total operating revenues         |         |                                 | 1,094,333
|                                       |                                                                                       |                                  |         |                                 |          
|Operating Expenses                     |                                                                                       |                                  |         |                                 |          
|                                       | Fuel                                                                                  |                                  |         | 302,631                         |          
|                                       | Plant operations and transmission costs                                               |                                  |         | 173,767                         |          
|                                       | Plant operating leases                                                                |                                  |         | 50,350                          |          
|                                       | Operation and maintenance services                                                    |                                  |         | 6,235                           |          
|                                       | Depreciation and amortization                                                         |                                  |         | 65,911                          |          
|                                       | Long-term incentive compensation                                                      |                                  |         | (3,291                          | )        
|                                       | Asset impairment and other charges                                                    |                                  |         | 85,924                          |          
|                                       | Administrative and general                                                            |                                  |         | 35,055                          |          
|                                       |                                                                                       |                                  |         |                                 |          
|                                       |                                                                                       | Total operating expenses         |         |                                 | 716,582  
|                                       |                                                                                       |                                  |         |                                 |          
|                                       | Operating income                                                                      |                                  |         | 377,751                         |          
|                                       |                                                                                       |                                  |         |                                 |          
|Other Income (Expense)                 |                                                                                       |                                  |         |                                 |          
|                                       | Interest and other income (expense)                                                   |                                  |         | (368                            | )        
|                                       | Gain on sale of assets                                                                |                                  |         |                                |          
|                                       | Interest expense                                                                      |                                  |         | (113,223                        | )        
|                                       | Dividends on preferred securities                                                     |                                  |         | (5,324                          | )        
|                                       |                                                                                       |                                  |         |                                 |          
|                                       |                                                                                       | Total other income (expense)     |         |                                 | (118,915 
|                                       |                                                                                       |                                  |         |                                 |          
|                                       | Income from continuing operations before income taxes and minority interest           |                                  |         | 258,836                         |          
|                                       | Provision for income taxes                                                            |                                  |         | 88,427                          |          
|                                       | Minority interest                                                                     |                                  |         | (7,550                          | )        
|                                       |                                                                                       |                                  |         |                                 |          
|Income From Continuing Operations      |                                                                                       |                                  | 162,859 |                                 |          
|                                       | Income (loss) from operations of discontinued foreign subsidiary, net of tax (Note 4) |                                  |         | (91                             | )        
|                                       |                                                                                       |                                  |         |                                 |          
|Income (Loss) Before Accounting Change |                                                                                       |                                  | 162,768 |                                 |          
|                                       | Cumulative effect of change in accounting for derivatives, net of tax                 |                                  |         |                                |          
|                                       | Cumulative effect of change in accounting for goodwill, net of tax                    |                                  |         |                                |          
|                                       |                                                                                       |                                  |         |                                 |          
|Net Income (Loss)                      |                                                                                       | $                                | 162,768 |                                 | $        
|                                       |                                                                                       |                                  |         |                                 |          

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
September 30,                                                                                                                                                                                                                        |         | Nine Months Ended
September 30, |        
|------------------------------------------------- | ----------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------- | ------------------------------- | -------
|
|
|Net Income (Loss)                                 |                                                                         | $                                                                                                                                                                                                                                                       | 162,768 |                                 | $      
|Other comprehensive income (expense), net of tax: |                                                                         |                                                                                                                                                                                                                                                         |         |                                 |        
|                                                  | Foreign currency translation adjustments:                               |                                                                                                                                                                                                                                                         |         |                                 |        
|                                                  |                                                                         | Foreign currency translation adjustments, net of income tax expense (benefit) of $20 and $1,725 for the three months and $2,131 and $(940) for the nine months ended September 30, 2002 and 2001, respectively                                          |         |                                 | (8,366 
|                                                  |                                                                         | Reclassification adjustments for sale of investment in a foreign subsidiary                                                                                                                                                                             |         |                                 |       
|                                                  | Unrealized gains (losses) on derivatives qualified as cash flow hedges: |                                                                                                                                                                                                                                                         |         |                                 |        
|                                                  |                                                                         | Cumulative effect of change in accounting for derivatives, net of income tax expense (benefit) of $(13,500) for the three months ended September 30, 2001 and $5,562 and $(124,400) for the nine months ended September 30, 2002 and 2001,
respectively |         |                                 |       
|                                                  |                                                                         | Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(16,087) and $5,500 for the three months and $(1,158) and $74,300 for the nine months ended September 30, 2002 and 2001,
respectively            |         |                                 | (67,482
|                                                  |                                                                         | Reclassification adjustments included in net income (loss), net of income tax expense (benefit) of $1,048 and $7,900 for the three months and $87 and $(9,700) for the nine months ended September 30, 2002 and 2001, respectively                      |         |                                 | 2,201  
|                                                  |                                                                         |                                                                                                                                                                                                                                                         |         |                                 |        
|Other comprehensive income (expense)              |                                                                         |                                                                                                                                                                                                                                                         | (73,647 | )                               |        
|                                                  |                                                                         |                                                                                                                                                                                                                                                         |         |                                 |        
|Comprehensive Income (Loss)                       |                                                                         | $                                                                                                                                                                                                                                                       | 89,121  |                                 | $      
|                                                  |                                                                         |                                                                                                                                                                                                                                                         |         |                                 |        

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)

|                                  |                                                                                                   | September 30,
2002                |            | December 31,
2001
|--------------------------------- | ------------------------------------------------------------------------------------------------- | --------------------------------- | ---------- | -----------------
|
|Assets                            |                                                                                                   |                                   |            |                  
|Current Assets                    |                                                                                                   |                                   |            |                  
|                                  | Cash and cash equivalents                                                                         |                                   | $          | 724,543          
|                                  | Accounts receivabletrade, net of allowance of $13,174 and $14,603 in 2002 and 2001, respectively |                                   |            | 376,752          
|                                  | Accounts receivableaffiliates                                                                    |                                   |            | 12,186           
|                                  | Assets under price risk management and energy trading                                             |                                   |            | 68,519           
|                                  | Inventory                                                                                         |                                   |            | 163,528          
|                                  | Prepaid expenses and other                                                                        |                                   |            | 94,503           
|                                  |                                                                                                   |                                   |            |                  
|                                  |                                                                                                   | Total current assets              |            |                  
|                                  |                                                                                                   |                                   |            |                  
|Investments                       |                                                                                                   |                                   |            |                  
|                                  | Energy projects                                                                                   |                                   |            | 1,602,945        
|                                  | Oil and gas                                                                                       |                                   |            | 27,354           
|                                  |                                                                                                   |                                   |            |                  
|                                  |                                                                                                   | Total investments                 |            |                  
|                                  |                                                                                                   |                                   |            |                  
|Property, Plant and Equipment     |                                                                                                   |                                   | 7,635,708  |                  
|                                  | Less accumulated depreciation and amortization                                                    |                                   |            | 903,592          
|                                  |                                                                                                   |                                   |            |                  
|                                  |                                                                                                   | Net property, plant and equipment |            |                  
|                                  |                                                                                                   |                                   |            |                  
|Other Assets                      |                                                                                                   |                                   |            |                  
|                                  | Long-term receivables                                                                             |                                   |            | 9,096            
|                                  | Goodwill                                                                                          |                                   |            | 658,137          
|                                  | Deferred financing costs                                                                          |                                   |            | 61,812           
|                                  | Long-term assets under price risk management and energy trading                                   |                                   |            | 111,671          
|                                  | Restricted cash and other                                                                         |                                   |            | 306,290          
|                                  |                                                                                                   |                                   |            |                  
|                                  |                                                                                                   | Total other assets                |            |                  
|                                  |                                                                                                   |                                   |            |                  
|Assets of Discontinued Operations |                                                                                                   |                                   | 9,393      |                  
|                                  |                                                                                                   |                                   |            |                  
|Total Assets                      |                                                                                                   | $                                 | 10,958,845 |                  
|                                  |                                                                                                   |                                   |            |                  

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)

|                                                |                                                                                                   | September 30,
2002                         |            | December 31,
2001 |          
|----------------------------------------------- | ------------------------------------------------------------------------------------------------- | ------------------------------------------ | ---------- | ----------------- | ---------
|
|Liabilities and Shareholder's Equity            |                                                                                                   |                                            |            |                   |          
|Current Liabilities                             |                                                                                                   |                                            |            |                   |          
|                                                | Accounts payableaffiliates                                                                       |                                            | $          | 8,764             |          
|                                                | Accounts payable and accrued liabilities                                                          |                                            |            | 371,873           |          
|                                                | Liabilities under price risk management and energy trading                                        |                                            |            | 30,484            |          
|                                                | Interest payable                                                                                  |                                            |            | 84,792            |          
|                                                | Short-term obligations                                                                            |                                            |            | 52,142            |          
|                                                | Current portion of long-term incentive compensation                                               |                                            |            | 5,346             |          
|                                                | Current maturities of long-term obligations                                                       |                                            |            | 171,207           |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total current liabilities                  |            |                   | 724,608  
|                                                |                                                                                                   |                                            |            |                   |          
|Long-Term Obligations Net of Current Maturities |                                                                                                   |                                            | 5,788,396  |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Long-Term Deferred Liabilities                  |                                                                                                   |                                            |            |                   |          
|                                                | Deferred taxes and tax credits                                                                    |                                            |            | 1,147,738         |          
|                                                | Deferred revenue                                                                                  |                                            |            | 450,480           |          
|                                                | Long-term incentive compensation                                                                  |                                            |            | 28,681            |          
|                                                | Long-term liabilities under price risk management and energy trading                              |                                            |            | 186,036           |          
|                                                | Other                                                                                             |                                            |            | 240,542           |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total long-term deferred liabilities       |            |                   | 2,053,477
|                                                |                                                                                                   |                                            |            |                   |          
|Liabilities of Discontinued Operations          |                                                                                                   |                                            | 3,702      |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Total Liabilities                               |                                                                                                   |                                            | 8,570,183  |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Minority Interest                               |                                                                                                   |                                            | 395,663    |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Preferred Securities of Subsidiaries            |                                                                                                   |                                            |            |                   |          
|                                                | Company-obligated mandatorily redeemable security of partnership holding solely parent debentures |                                            |            | 150,000           |          
|                                                | Subject to mandatory redemption                                                                   |                                            |            | 117,400           |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total preferred securities of subsidiaries |            |                   | 267,400  
|                                                |                                                                                                   |                                            |            |                   |          
|Commitments and Contingencies (Note 6)          |                                                                                                   |                                            |            |                   |          
|Shareholder's Equity                            |                                                                                                   |                                            |            |                   |          
|                                                | Common stock, no par value; 10,000 shares authorized; 100 shares issued and outstanding           |                                            |            | 64,130            |          
|                                                | Additional paid-in capital                                                                        |                                            |            | 2,634,025         |          
|                                                | Retained deficit                                                                                  |                                            |            | (701,077          | )        
|                                                | Accumulated other comprehensive loss                                                              |                                            |            | (271,479          | )        
|                                                |                                                                                                   |                                            |            |                   |          
|Total Shareholder's Equity                      |                                                                                                   |                                            | 1,725,599  |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Total Liabilities and Shareholder's Equity      |                                                                                                   | $                                          | 10,958,845 |                   | $        
|                                                |                                                                                                   |                                            |            |                   |          

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)

|                                                                        |                                                                               | Nine Months Ended
September 30,                                 |         
|----------------------------------------------------------------------- | ----------------------------------------------------------------------------- | --------------------------------------------------------------- | --------
|
|
|Cash Flows From Operating Activities                                    |                                                                               |                                                                 |         
|                                                                        | Income from continuing operations, after accounting change, net               |                                                                 | $       
|                                                                        | Adjustments to reconcile income to net cash provided by operating activities: |                                                                 |         
|                                                                        |                                                                               | Equity in income from energy projects                           |         
|                                                                        |                                                                               | Equity in income from oil and gas investments                   |         
|                                                                        |                                                                               | Distributions from energy projects                              |         
|                                                                        |                                                                               | Dividends from oil and gas                                      |         
|                                                                        |                                                                               | Depreciation and amortization                                   |         
|                                                                        |                                                                               | Amortization of discount on short-term obligations              |         
|                                                                        |                                                                               | Deferred taxes and tax credits                                  |         
|                                                                        |                                                                               | Gain on sale of assets                                          |         
|                                                                        |                                                                               | Asset impairment and other charges                              |         
|                                                                        |                                                                               | Cumulative effect of change in accounting, net of tax           |         
|                                                                        | Changes in operating assets and liabilities:                                  |                                                                 |         
|                                                                        |                                                                               | Decrease in accounts receivable                                 |         
|                                                                        |                                                                               | Decrease (increase) in inventory                                |         
|                                                                        |                                                                               | Decrease (increase) in prepaid expenses and other               |         
|                                                                        |                                                                               | Increase (decrease) in accounts payable and accrued liabilities |         
|                                                                        |                                                                               | Increase (decrease) in interest payable                         |         
|                                                                        |                                                                               | Decrease in long-term incentive compensation                    |         
|                                                                        |                                                                               | Decrease (increase) in assets under risk management, net        |         
|                                                                        | Other operating, net                                                          |                                                                 |         
|                                                                        |                                                                               |                                                                 |         
|                                                                        |                                                                               |                                                                 | 568,380 
|                                                                        | Operating cash flow from discontinued operations                              |                                                                 |         
|                                                                        |                                                                               |                                                                 |         
|                                                                        |                                                                               | Net cash provided by 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, net                                                     |                                                                 |         
|                                                                        | Cash dividends to parent                                                      |                                                                 |         
|                                                                        | Funds provided to discontinued operations                                     |                                                                 |         
|                                                                        | Issuance of preferred securities                                              |                                                                 |         
|                                                                        | Redemption of preferred securities                                            |                                                                 |         
|                                                                        |                                                                               |                                                                 |         
|                                                                        |                                                                               |                                                                 | (205,073
|                                                                        | 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                                                                    |                                                                 |         
|                                                                        |                                                                               |                                                                 |         
|                                                                        |                                                                               |                                                                 | (120,633
|                                                                        | Investing cash flow from discontinued operations                              |                                                                 |         
|                                                                        |                                                                               |                                                                 |         
|                                                                        |                                                                               | Net cash used in investing activities                           |         
|                                                                        |                                                                               |                                                                 |         
|Effect of exchange rate changes on cash                                 |                                                                               |                                                                 | 14,766  
|                                                                        |                                                                               |                                                                 |         
|Net increase (decrease) in cash and cash equivalents                    |                                                                               |                                                                 | 293,427 
|Cash and cash equivalents at beginning of period                        |                                                                               |                                                                 | 434,249 
|                                                                        |                                                                               |                                                                 |         
|Cash and cash equivalents at end of period                              |                                                                               |                                                                 | 727,676 
|Cash and cash equivalents classified as part of discontinued operations |                                                                               |                                                                 | (3,133  
|                                                                        |                                                                               |                                                                 |         
|Cash and cash equivalents of continuing operations                      |                                                                               | $                                                               | 724,543 
|                                                                        |                                                                               |                                                                 |         

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        SEPTEMBER 30, 2002

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 nine months ended September 30, 2002 are not necessarily indicative of the operating
results for the full year.

Our
significant accounting policies are described in Note 2 to our Consolidated Financial Statements as of December 31, 2001 and 2000, included in our 2001 Annual Report on
Form 10-K filed with the Securities and Exchange Commission on April 1, 2002. We follow the same accounting policies for interim reporting purposes. This quarterly report
should be read in connection with such financial statements.

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 have adversely affected independent power producers and subsidiaries of major integrated energy companies who sell a sizable
portion of their generation into the wholesale energy market (sometimes referred to as merchant generators). These developments include depressed 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, and the decline of liquidity in the energy markets as a result of tightening credit and
increasing concern about the ability of counter-parties to perform their obligations. In addition, many merchant generators and power trading firms have announced plans to improve their financial
position through asset sales, the cancellation or deferral of substantial new development, significant reductions in or elimination of trading activities, decreases in capital expenditures, including
cancellations of orders for new turbines, and reductions in operating costs.

Our Situation

Because of the 2000-2001 California power crisis, and its indirect effect on us, we began in early 2001 to shift our emphasis from the development and
acquisition of projects to focus instead on enhancing the performance of our existing projects and on maintaining credit quality. As a result, during 2001 and early 2002, we completed the sale of
several non-strategic project investments, and, during the first quarter of 2002, further reduced business development activities and undertook a related effort to reduce both corporate
overhead and other expenditures across the organization and reduce debt.

Notwithstanding
these efforts, in 2002, we have been affected by lower wholesale prices of energy and capacity, particularly at our Homer City facilities in Pennsylvania, and by the
diminished ability to enter into forward contracts for the sale of power primarily from these facilities because of the credit constraints affecting us and many of our counter-parties.

Our
Illinois Plants have been largely unaffected by these developments because Exelon Generation is under contract to buy substantially all of the capacity of these units for the balance
of 2002. However, as permitted by the power purchase agreements, Exelon Generation has advised us that it will not purchase 2,684 megawatts (MW) of the capacity from our coal-fired units
and 1,864 MW of capacity from our Collins Station and small peaking units for 2003 and 2004 and Exelon Generation

6

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has the further right to release an additional 3,043 MW for 2004. As a result, beginning in 2003, the portion of our generation to be sold into the wholesale markets will significantly increase,
thereby increasing our merchant risk. See "Management's Discussion and Analysis of Results of Operations and Financial ConditionMarket Risk ExposuresIllinois Plants."

As
a result of these and other factors, Moody's downgraded our credit rating and the credit ratings of our largest subsidiary, Edison Mission Midwest Holdings, on October 1, 2002
as shown in the following table:

|Rated Entities                                    |  | Moody's Rating
prior to Downgrade |  | Moody's Rating
after Downgrade
|------------------------------------------------- |  | --------------------------------- |  | ------------------------------
|Edison Mission Energy senior unsecured debt       |  | Baa3                              |  | Ba3                           
|Edison Mission Midwest Holdings Co. bank facility |  | Baa2                              |  | Ba2                           

In
addition, Standard & Poor's has placed our credit ratings on CreditWatch with negative implications. See "Management's Discussion and Analysis of Results of Operations and
Financial ConditionLiquidity and Capital ResourcesCredit Ratings."

Against
this background, we have undertaken a number of actions to reduce our commitments and expenditures, thereby improving our cash flow. These actions include:



We
have also reduced our already modest non asset-backed trading activities in Boston, and focused almost exclusively on the sale of power from our facilities and related risk management
activities.

In
addition, we continue to review the possibility of sales of assets, but believe that current market conditions may inhibit our ability to obtain prices commensurate with our valuation
of those investments which we might offer for sale. For a discussion of our current financial condition, see "Management's Discussion and Analysis of Results of Operations and Financial
ConditionLiquidity and Capital Resources."

NOTE 2. INVENTORY

Inventory is stated at the lower of weighted average cost or market. Inventory at September 30, 2002 and December 31, 2001 consisted of the
following:

September 30,
2002

December 31,
2001(Unaudited)(in millions)Coal and fuel oil

$
102.7

$
110.1Spare parts, materials and supplies


60.8


57.3Total

$
163.5

$
167.4


7

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NOTE 3. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

|                                          |  | Currency
Translation
Adjustments |        | Unrealized Gains
(Losses) on Cash
Flow Hedges |   | Accumulated Other
Comprehensive
Income (Loss) |  
|----------------------------------------- |  | -------------------------------- | ------ | --------------------------------------------- | - | --------------------------------------------- | -
|Balance at December 31, 2001              |  | $                                | (133.4 | )                                             | $ | (168.4                                        | )
|Current period change                     |  |                                  | 70.9   |                                               |   | (40.6                                         | )
|                                          |  |                                  |        |                                               |   |                                               |  
|Balance at September 30, 2002 (Unaudited) |  | $                                | (62.5  | )                                             | $ | (209.0                                        | )
|                                          |  |                                  |        |                                               |   |                                               |  

Unrealized
gains (losses) on cash flow hedges included those related to the hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our 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. Approximately
46% of our accumulated other comprehensive loss at September 30, 2002 related to net unrealized losses on the cash flow hedge resulting from this contract. These losses arise because current
forecasts of future electricity prices in these markets are greater than our contract prices. In addition to this contract, unrealized gains (losses) on cash flow hedges included those related to our
share of interest rate swaps of our unconsolidated affiliates and the Loy Yang B project.

As
our hedged positions are realized, approximately $9.1 million, after tax, of the net unrealized gains on cash flow hedges at September 30, 2002 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 gains associated with them will be offset. The
maximum period over which we have
designated a cash flow hedge, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is 14 years.

NOTE 4. DISCONTINUED OPERATIONS

On December 21, 2001, Edison First Power Limited 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. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. Net proceeds from the
sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants. We recorded an after-tax
loss during 2001 of $1.1 billion related to the loss on disposal of these assets. The results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the
consolidated financial statements in accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The consolidated financial statements have been
restated to conform to discontinued operations treatment for all historical periods presented.

During
the second quarter of 2002, we recorded income of $3.1 million from discontinued operations primarily related to an insurance recovery from claims filed prior to the sale
of the power plants.

Effective
January 1, 2001, we recorded a $5.8 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting
for derivatives. The majority of our activities related to the Ferrybridge and Fiddler's Ferry power plants did not qualify for either the normal purchases and sales exception or as cash flow hedges
under SFAS No. 133. We could not conclude, based on information available at January 1, 2001, that the timing of generation from these power plants met the probable requirement for a
specific forecasted transaction under SFAS No. 133.

8

---

Accordingly, the majority of these contracts were recorded at fair value with subsequent changes in fair value recorded through the income statement.

Summarized
results of discontinued operations are as follows:

|                                                                                              |  | Three Months Ended
September 30, |      | Nine Months Ended
September 30, |  
|--------------------------------------------------------------------------------------------- |  | -------------------------------- | ---- | ------------------------------- | -
|
|
|Total operating revenues                                                                      |  | $                                |     |                                 | $
|Income (loss) before income taxes                                                             |  |                                  | (0.1 | )                               |  
|Income (loss) before accounting change                                                        |  |                                  | (0.1 | )                               |  
|Cumulative effect of change in accounting, net of income tax expense of $2.5 million for 2001 |  |                                  |     |                                 |  
|Income (loss) from operations of discontinued foreign subsidiary                              |  | $                                | (0.1 | )                               | $

The
following summarizes the balance sheet information of the discontinued operations (in millions):

September 30,
2002

December 31,
2001(Unaudited)Cash and cash equivalents

$
3.1

$
62.1Accounts receivabletrade, net of allowance of $1.9 million and $1.4 million in 2002 and 2001, respectively


5.3


88.4Other current assets


1.0


1.5Total current assets


9.4


152.0Other assets





1.6Total long-term assets





1.6Assets of discontinued operations

$
9.4

$
153.6Accounts payable and accrued liabilities

$
3.7

$
51.6Interest payable





4.2Total current liabilities


3.7


55.8Liabilities of discontinued operations

$
3.7

$
55.8


9

---

NOTE 5. RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

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):

September 30,
2002

December 31,
2001(Unaudited)Derivatives:Interest rate:Interest rate swap/cap agreements

$
(39.7
)
$
(35.8
)Interest rate options


(1.1
)

(1.0
)Commodity price:Forwards


38.6


63.8Futures


(0.5
)

(8.4
)Options


(0.6
)

0.4Swaps


(141.8
)

(137.6
)Foreign currency forward exchange agreements


(0.3
)

(0.6
)Cross currency interest rate swaps


14.9


27.6


In
assessing the fair value of our non-trading derivative financial instruments, we use 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 our commodity risk
management assets and liabilities (as of September 30, 2002) (in millions):

|                                                   |  | Total Fair
Value |        | Maturity
<1 year |   | Maturity
1 to 3
years |   | Maturity
4 to 5
years |      | Maturity
>5 years |  
|-------------------------------------------------- |  | ---------------- | ------ | ---------------- | - | --------------------- | - | --------------------- | ---- | ----------------- | -
|
|Prices actively quoted                             |  | $                | 7.5    |                  | $ | 5.3                   |   | $                     | 2.3  |                   | $
|Prices based on models and other valuation methods |  |                  | (111.8 | )                |   | (7.3                  | ) |                       | (7.0 | )                 |  
|                                                   |  |                  |        |                  |   |                       |   |                       |      |                   |  
|Total                                              |  | $                | (104.3 | )                | $ | (2.0                  | ) | $                     | (4.7 | )                 | $
|                                                   |  |                  |        |                  |   |                       |   |                       |      |                   |  

The
fair value of the electricity rate swap agreements (included under commodity price-swaps) entered into by the Loy Yang B 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

On September 1, 2000, we acquired the trading operations of Citizens Power LLC and, subsequently, combined them with our risk management and trading
operations, now conducted by our subsidiary, Edison Mission Marketing & Trading, Inc. As a result of a number of industry and credit related factors, we have minimized our price risk
management activities and our trading activities with third parties not related to our power plants or investments in energy projects. See "Management's Discussion and Analysis of Results of
Operations and Financial ConditionCurrent Developments." To the extent we engage in trading activities, we seek to manage price risk and 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.
Approximately 2,746 GWh of our energy trading contracts (excluding the power sales agreement with

10

---

an unaffiliated electric utility) were physically settled during the third quarter ended September 30, 2002. We generally balance forward sales and purchase contracts and manage our exposure
through a value at risk analysis as described further below.

The
fair value of the financial instruments, including forwards, futures, options and swaps, related to trading activities as of September 30, 2002 and December 31, 2001,
which include energy commodities, are set forth below (in millions):

September 30, 2002

December 31, 2001Assets

Liabilities

Assets

Liabilities(Unaudited)Forward contracts

$
123.5

$
27.5

$
4.6

$
2.9Futures contracts


0.1





0.1


0.1Option contracts


0.1








Swap agreements


5.9


6.2


0.2


Total

$
129.6

$
33.7

$
4.9

$
3.0


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 we purchased and restructured and a long-term power supply agreement with another unaffiliated party. We 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 our energy trading assets and liabilities (as of September 30, 2002)
(in millions):

|                                                   |  | Total Fair
Value |      | Maturity
<1 year |   | Maturity
1 to 3
years |   | Maturity
4 to 5
years |      | Maturity
>5 years
|-------------------------------------------------- |  | ---------------- | ---- | ---------------- | - | --------------------- | - | --------------------- | ---- | -----------------
|
|Prices actively quoted                             |  | $                | 2.5  |                  | $ | 5.4                   |   | $                     | (2.9 | )                
|Prices based on models and other valuation methods |  |                  | 93.4 |                  |   | (3.4                  | ) |                       | 3.3  |                  
|                                                   |  |                  |      |                  |   |                       |   |                       |      |                  
|Total                                              |  | $                | 95.9 |                  | $ | 2.0                   |   | $                     | 0.4  |                  
|                                                   |  |                  |      |                  |   |                       |   |                       |      |                  

The
net realized and unrealized gains or losses arising from energy trading activities for the three and nine month periods ended September 30, 2002 and 2001 are as follows (in
millions):

Three Months Ended
September 30,

Nine Months Ended
September 30,2002

2001

2002

2001(Unaudited)Operating RevenuesForward contracts

$
19.8

$
5.6

$
40.0

$
7.2Futures contracts


(0.1
)

0.1


(0.7
)

(1.8
)Option contracts


(0.5
)

(3.0
)

(1.0
)

(0.1
)Swap agreements


(5.6
)

0.4


(1.7
)

0.2Total

$
13.6

$
3.1

$
36.6

$
5.5


The
unrealized gain (loss) from energy trading activities included in the above amounts was $2 million and $6.3 million for the three month periods ended
September 30, 2002 and 2001, and $13.3 million and $(10.6) million for the nine month periods ended September 30, 2002 and 2001, respectively.

11

---

NOTE 6. COMMITMENTS AND CONTINGENCIES

Capital Expenditures

The capital program at the Illinois Plants has been reduced by $310 million for the period 2003-2005 as a result of the suspension of work
related to two SCRs for the Powerton Station. As a result of the decision to suspend work on this project, we recorded an impairment charge of $25.4 million during the third quarter ended
September 30, 2002, due to the write-off of capitalized costs associated with these environmental improvements. This decision to reduce capital expenditures was made in light of
current market conditions. See "Management's Discussion and Analysis of Results of Operations and Financial ConditionMarket Risk Exposures" and "Management's Discussion and Analysis of
Results of Operations and Financial ConditionEnvironmental Matters and Regulations."

On
August 9, 2002, our subsidiary, Midwest Generation, LLC, exercised its option to purchase the Illinois peaker power units that were subject to a lease with a third-party
lessor. As disclosed in "Off-Balance Sheet Transactions" in our 2001 Annual Report on Form 10-K, this operating lease was structured to maintain a minimum amount of
equity (3% of the acquisition price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases).
In order to fund the purchase, we received $255 million as repayment of the note receivable held by us and paid $300 million plus outstanding lease obligations to the owner-lessor.
Accordingly, our net cash outlay was $45.7 million. See our 2001 Annual Report on Form 10-K for further information on off-balance sheet transactions.

In
September 2002, we notified Siemens Westinghouse of our election to terminate all of our equipment purchase contracts for nine turbines effective October 25, 2002. The
termination of the equipment purchase order reduced our projected capital expenditures by $53 million. We recorded a $60.5 million pre-tax loss in the third quarter of 2002
related to the write-off of capitalized costs associated with the turbines.

Commercial Commitments

The following table summarizes our consolidated commercial commitments as of September 30, 2002. 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                              |  | $                                         | 44.1 | 
|Firm commitments for asset purchase                    |  |                                           |     | 
|Firm commitments to contribute project equity          |  |                                           | 35.2 | 
|Environmental improvements at our project subsidiaries |  |                                           | 14.0 | 
|                                                       |  |                                           |      | 
|Total Commercial Commitments                           |  | $                                         | 93.3 | 
|                                                       |  |                                           |      | 

12

---

Credit Support for Price Risk Management and Trading Activities

Our domestic price risk management and trading activities are conducted through our subsidiary, Edison Mission Marketing & Trading, Inc.
Traditionally, we have provided guarantees to support Edison Mission Marketing & Trading's contracts. On October 1, 2002, Moody's downgraded our credit rating below investment grade.
Standard & Poor's has also placed our credit rating on CreditWatch with negative implications. Following the Moody's downgrade, we have provided $5.2 million (as of November 7,
2002) in letters of credit in response to requests for credit support and could be required to provide additional letters of credit or collateral in the future. It is likely that many of Edison
Mission Marketing & Trading's future transactions will be supported by letters of credit or cash collateral instead of our guarantees. See "Management's Discussion and Analysis of Results of
Operations and Financial ConditionLiquidity and Capital ResourcesCredit Ratings."

Our
United Kingdom price risk management activities for our First Hydro project are managed through our subsidiary, Edison Mission Marketing and Services Limited. We currently provide
guarantees for most of First Hydro's grid trade master agreements (referred to as GTMAs) with third-party counter-parties in order to support the credit of First Hydro. As a result of Moody's rating
actions as described above, we have been and may be in the future requested to provide credit support in the form of letters of credit or cash instead of our guarantees. To this end, our subsidiary,
Edison Mission Operation and Maintenance Limited, has obtained a cash collateralized credit facility in the amount of £17 million, under which letters of credit totaling
£11.4 million have been issued as of October 17, 2002.

We
anticipate that sales of power from our Illinois Plants, Homer City facilities and First Hydro plants in the United Kingdom may require additional credit support over the next twelve
months, 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 our risk management and trading activities. We currently project the potential working capital to support our price risk management and trading activity to be between $100 million
and $200 million from time to time over the next twelve months.

Firm Commitments for Asset Purchase

Project

Local Currency

U.S. Currency(in millions)Italian Wind and Expansion(i)

4.9 million Euro

$
4.8


---

13

---

Firm Commitments to Contribute Project Equity

Project

U.S. Currency(in millions)CBK(i)

$
48.5Italian Wind Expansion(ii)

$
2.3Sunrise(iii)

$
54.1


---

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

Contingencies

Paiton Project

Our wholly-owned subsidiary owns a 40% interest in PT Paiton Energy, which owns a 1,230 MW coal-fired power plant in operation in East Java,
Indonesia, which is referred to as the Paiton project. Under the terms of a long-term power purchase agreement between Paiton Energy and PT PLN, the state-owned electric utility company,
PT PLN is required to pay for capacity and fixed operating costs since each unit and the plant have achieved commercial operation.

14

---

PT
PLN and Paiton Energy signed a Binding Term Sheet on December 14, 2001 setting forth the commercial terms under which Paiton Energy is to be paid for capacity and energy
charges, as well as a monthly "restructure settlement payment" covering arrears owed by PT PLN ($456 million at December 31, 2001) and the settlement of other claims. In addition, the
Binding Term Sheet provides for an extension of the term of the power purchase agreement from 2029 to 2040. The Binding Term Sheet serves as the basis under which PT PLN has paid Paiton Energy
beginning January 1, 2002. On June 28, 2002, Paiton Energy and PT PLN concluded negotiations on an amendment to the power purchase agreement that includes the agreed commercial terms in
the Binding Term Sheet. The Binding Term Sheet will remain in effect until all conditions for effectiveness of the amendment to the power purchase agreement are completed by both parties, which
conditions are required to be completed by December 31, 2002. Previously, PT PLN and Paiton Energy entered into an interim agreement (covering February to December 31, 2000), a
Phase I Agreement (covering January 1 to June 30, 2001), a Phase II Agreement (covering July 1 to September 30, 2001) and a Phase III Agreement
(covering October 1 to December 31, 2001). PT PLN made all of the payments to Paiton Energy as required under these agreements, which were superseded by the Binding Term Sheet. Paiton
Energy continues to generate electricity to meet the power demand in the region. PT PLN has paid invoices for the months of January through August 2002, as well as the restructure settlement
payments due for the months of January through September 2002, as required and in accordance with the billing procedures agreed in the Binding Term Sheet and the power purchase agreement.
Paiton Energy believes that PT PLN will continue to make payments for electricity under the Binding Term Sheet
while the parties work to complete the conditions precedent to the effectiveness of the amendment to the power purchase agreement.

Our
investment in the Paiton project increased to $515.8 million at September 30, 2002 from $492.1 million at December 31, 2001. The increase in the
investment account resulted from our subsidiary recording its proportionate share of net income from Paiton Energy as well as its proportionate share of other comprehensive income. Our investment in
the Paiton project will increase (decrease) from earnings (losses) from Paiton Energy and decrease by cash distributions. Assuming Paiton Energy remains profitable, we expect the investment account to
increase substantially during the next several years as earnings are expected to exceed cash distributions.

Under
the Binding Term Sheet, past due accounts receivable due under the original power purchase agreement are to be compensated through a restructure settlement payment in the amount of
US$4 million per month for a period of 30 years. If the power purchase agreement amendment does not become effective within 180 days of its signing, the parties would be entitled
to revert to the terms and conditions of the original power purchase agreement in order to pursue arbitration in an international forum.

While
the Binding Term Sheet has been approved by the project lenders, Paiton Energy has not yet obtained approval of the amendment to the power purchase agreement by the project
lenders. Paiton Energy and its government agency lenders have agreed to Summary Terms and Conditions for Debt Restructuring of Paiton Energy, which terms and conditions have been approved by the
commercial bank lenders to the project. In addition, Paiton Energy must seek approval of the debt restructuring from its bond holders. Paiton Energy believes that the debt restructuring will receive
the necessary approvals from the bond holders. Therefore, we believe that we will ultimately recover our investment in the project.



PT Batu Hitam Perkasa (BHP), one of the other shareholders in Paiton Energy, has reinstated the pending arbitration to resolve disputes under the fuel supply
agreement between BHP and Paiton Energy. The arbitration had been stayed since 1999 to allow the parties to engage in settlement discussions to restructure the coal supply chain for the Paiton
project. These discussions did not result

15

---

in a settlement of all potential claims with respect to the restructuring of the coal supply chain, and BHP recently requested that the arbitration tribunal permit BHP to amend or supplement its
statement of claims to assert additional claims against Paiton Energy for breach and termination of the fuel supply agreement. BHP's total claim, to date, is $250 million.

Paiton
Energy has entered into settlement negotiations with BHP. A settlement offer has been made, and BHP has indicated that it may be willing to accept that offer, subject to the
execution of acceptable documentation and the timing of payment. Such settlement is subject to Paiton Energy obtaining approval of its lenders. We believe that the outcome of this arbitration will not
have a material adverse effect on our consolidated financial position or results of operations.

Lakeland Project

The combination of the introduction of the New Electricity Trading Arrangements (replacing the "pool" system of electricity sales in the United Kingdom) and the
so-called Transfer Scheme (separating the supply and distribution businesses in the United Kingdom) required material amendment to Lakeland's power sales agreement and related documents.
By October 2002, agreement had been reached with Norweb Energi Ltd (the counter-party under the Lakeland power sales agreement and an indirect subsidiary of TXU Europe) and all other
relevant parties as to the form of the necessary amendments, but the documentation to implement this agreement was awaiting actual signature and has not yet been signed.

On
October 14, 2002, TXU Corp., the U.S. parent company of TXU Europe, announced that it would not provide additional funding for its European business and was considering selling
all or a portion of this business. On October 21, 2002, TXU Corp. announced the sale by its indirect subsidiary, TXU (United Kingdom) Ltd. of all its retail customer contracts in the
United Kingdom. Concurrently, TXU announced its intention to renegotiate certain power sales agreements, including the Lakeland power sales agreement, as part of an effort to restructure its
operations and preserve creditor value. TXU further indicated that failure to renegotiate these agreements or otherwise to restructure its operations could result in the equivalent of bankruptcy in
the United Kingdom for one or more of TXU's subsidiaries, including possibly Norweb Energi Ltd.

Currently,
we continue to deliver power under the Lakeland power sales agreement and Norweb Energi Ltd has made all payments. We cannot determine, however, the outcome of TXU's
restructuring activities in Europe, nor the effect of such activities upon the Lakeland power sales agreement. If the power sales agreement is terminated, we could operate the Lakeland project as a
merchant plant, but because of current depressed power prices in the United Kingdom market, we may not be able to operate the plant profitably in the near term. Although cash is held by the project,
we do not anticipate any distributions unless and until the uncertainties surrounding the power sales agreement are resolved. Further, during the fourth quarter, we will complete an asset impairment
evaluation taking into

16

---

consideration continuing developments with respect to the power sales agreement. The condensed financial position of the Lakeland project at September 30, 2002 is set forth below:

September 30,
2002(Unaudited)
(in millions)Cash

$
32.4Property, plant and equipment


138.0Other assets


13.8Total assets

$
184.2Accounts payable

$
12.0Debt


72.2Deferred taxes


32.1Equity


67.9Total liabilities and equity

$
184.2


Brooklyn Navy Yard Project

Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. Our 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. for damages in the amount of
$136.8 million. Brooklyn Navy Yard has also filed an action entitled Brooklyn Navy Yard Cogeneration Partners, L.P. v. PMNC, Parsons Main of New York, Inc., Nab Construction
Corporation, L.K. Comstock & Co., Inc. and The Parsons Corporation, in the Supreme Court of the State of New York, Kings County, Index No. 5966/97 asserting general monetary
claims in excess of $13 million under the construction turnkey agreement. On March 26, 1998, the Superior Court in the California action granted PMNC's motion for attachment in the
amount of $43 million against Brooklyn Navy Yard and attached a Brooklyn Navy Yard bank account in the amount of $0.5 million. Brooklyn Navy Yard unsuccessfully appealed the attachment
order. On the same day, the court stayed all proceedings in the California action pending the New York action. PMNC's motion to dismiss the New York action was denied by the New York Supreme Court and
further denied on appeal in September 1998. On March 9, 1999, Brooklyn Navy Yard filed a motion for partial summary judgment in the New York action. The motion was denied and Brooklyn
Navy Yard has appealed. The appeal and the commencement of discovery were suspended until June 2000 to allow for voluntary mediation between the parties. The mediation ended unsuccessfully on
March 23, 2000. On November 13, 2000, a New York appellate court issued a ruling granting summary judgment in favor of Brooklyn Navy Yard, striking PMNC's cause of action for quantum
meruit, and limiting PMNC to its claims under the
construction contract. On February 14, 2002, PMNC moved to amend the complaint in the New York action to add us as a defendant and to seek a $43 million attachment against us. This
motion was heard on May 10, 2002, and the court issued an order denying the motion on June 21, 2002. Trial was originally scheduled for October 21, 2002, and has now been
rescheduled for January 2, 2003. The parties filed motions for summary judgment in October 2002, but no hearings have been scheduled. In connection with a $407 million
non-recourse project refinancing in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and our partner from all claims and costs arising from or in connection with the
contractor litigation, which indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. Any further payments which would be due to the contractor with respect to completion of
construction of the power plant would be accounted for as an addition to the power plant investment. Furthermore, our partner has executed a reimbursement agreement with us that provides recovery of
up to $10 million over an initial amount, including legal fees, payable from its management fees, royalty fees, and

17

---

distributions (if any) from the project. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of operations.

ISAB Project

In connection with the financing of the ISAB project, which is located near Siracusa in Sicily, Italy, we have guaranteed for the benefit of the banks financing
the construction of the ISAB project our subsidiary's obligation to contribute project equity and subordinated debt totaling up to approximately $36 million. The amount of payment under the
obligation is contingent upon the outcome of an arbitration proceeding brought in 1999 by the contractor of the project against ISAB Energy. On April 19, 2002, the arbitration tribunal issued a
partial award on liability dismissing 10 of the contractor's 14 claims. The tribunal found there was a legal and factual basis for a "slight extension" of the guaranteed completion date and a "slight
indemnification" of the contractor in relation to the four successful claims. Certain additional minor claims of the contractor, together with ISAB Energy's counterclaims for defects and delay
liquidated damages, are still to be heard by the tribunal on a date to be agreed by the parties or as otherwise directed by the tribunal. We believe that the outcome of this arbitration will not have
a material adverse effect on our consolidated financial position or results of operations.

Regulatory Developments Affecting Sunrise Power Company

Sunrise Power Company, in which our wholly-owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources under a
power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints
with the Federal Energy Regulatory Commission against all sellers of long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California
Public Utilities Commission complaint alleged that the contracts are "unjust and unreasonable" on price and other terms, and requested that the contracts be abrogated. The California Electricity
Oversight Board complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water Resources or, in
the alternative, abrogated as of a future date, to allow for the possibility of renegotiation. After hearings and intermediate rulings, on July 23, 2002, the Federal Energy Regulatory
Commission dismissed with prejudice the California Public Utilities Commission and California Electricity Oversight Board complaints against Sunrise. Notwithstanding the fact that the July 23
order was, in part, a denial of rehearing sought previously, the California Public Utilities Commission and the Energy Oversight Board then filed a request for rehearing of the July 23 order.
In a notice issued on September 20, 2002, the Federal Energy Regulatory Commission stated that it did not intend to act on such request. It is possible that the California Public Utilities
Commission and the Energy Oversight Board may try to appeal within 60 days after the September 20, 2002 notice to the federal courts of appeal.

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 a copy of the
complaint.

On
May 15, 2002, Sunrise 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

18

---

California Department of Water Resources, including Sunrise. The lawsuit alleges that the defendants, including Sunrise, 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. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of
operations.

Regulatory Developments Affecting Doga Project

On August 4, 2002, the Electricity Market License Regulation was implemented in Turkey. The new regulation contains, among other things, a requirement to
obtain a generation license. Historically, Doga's Implementation Contract has been its sole license. The new regulation contemplates a fixed license obtaining 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 than those in the Implementation Contract.

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 in March
or April of 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.

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 for the 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.

Federal Income Taxes

Edison International received a notice on August 7, 2002, from the Internal Revenue Service (IRS) asserting deficiencies in Edison Mission Energy's federal
corporation income taxes for its 1994 to 1996 tax years. Edison International filed a timely protest to this notice. We believe that we have meritorious legal defenses to those deficiencies and
believe that the ultimate outcome of this matter will not result in a material impact on our consolidated results of operations or financial position.

Indemnities



Some of our subsidiaries have entered into indemnification agreements, under which the subsidiaries agreed to repay capacity payments to the projects' power
purchasers in the event the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. Obligations under these
indemnification agreements as of September 30, 2002, if payment were required, would be $218.1 million. We have no reason to believe that the projects will either terminate their
performance or reduce their electric power producing capability during the term of the power contracts.

19

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In support of the business of our subsidiaries, we have, from time to time, entered into guarantees and indemnity agreements with respect to our subsidiaries'
obligations such as debt service, fuel supply or the delivery of power, and have also entered into reimbursement agreements with respect to letters of credit issued to third parties to support our
subsidiaries' obligations. We have also, from time to time, entered into guarantees and indemnification agreements with respect to acquisitions made by our subsidiaries. In this regard, we have
indemnified the previous owners of the Illinois Plants, the Homer City facilities and the EcoEléctrica facilities for specified liabilities, including environmental liabilities,
incurred as a result of their prior ownership of the plants. We do not believe these indemnification obligations will have a material impact on us.

Tax Indemnity Agreements

In connection with the sale-leaseback transactions that we have entered into related to the Collins Station, Powerton and Joliet plants in Illinois
and the Homer City facilities in Pennsylvania, we have entered into tax indemnity agreements. Under these tax indemnity agreements, we have agreed to indemnify the equity investors in the
sale-leaseback transactions for specified adverse tax consequences. The potential indemnity obligations under these tax indemnity agreements could be significant. However, we believe it is
not likely that an event requiring material tax indemnification will occur under any of these agreements.

Litigation

We experience other routine litigation in the normal course of our business. None of such pending routine litigation is expected to have a material adverse effect
on our consolidated financial position or results of operations.

Chicago In-City Obligation

Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, our subsidiary committed to install one or more
gas-fired electric generating units having an additional gross dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago (referred to as the
In-City Obligation). The acquisition documents require that commercial operation of this project commence by December 15, 2003. Due to additional capacity for new
gas-fired generation in the Mid-America Interconnected Network, generally referred to as the MAIN Region, and the improved reliability of power generation in the Chicago area,
we are in discussions with Commonwealth Edison and the City of Chicago regarding alternatives to construction of 500 MW of capacity, which we do not believe is needed at this time. There can be no
assurance that these discussions will result in an agreement to terminate the In-City Obligation. If we were to install this additional capacity, we estimate that the cost could be as much
as $320 million.

Contingent Obligations to Contribute Project Equity

Project

Local Currency

U.S. Currency(in millions)Paiton(i)



$
5.3ISAB(ii)

36.8 million Euro

$
36.3


---

20

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We
are not aware of any other significant contingent obligations to contribute project equity.

Environmental

We believe that we are in substantial compliance with environmental regulatory requirements; however, possible future developments, such as the enactment of more
stringent environmental laws and regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance
that we would be able to recover increased costs from our customers or that our financial position and results of operations would not be materially affected.

NOTE 7. BUSINESS SEGMENTS

We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific, and
Europe and Middle East. Our 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 and
Middle East |  | Corporate/
Other |         | Total
|----------------------- |  | -------- | ------- | ------------ | - | ---------------------- |  | ---------------- | ------- | -----
|
|September 30, 2002      |  |          |         |              |   |                        |  |                  |         |      
|Operating revenues      |  | $        | 766.4   |              | $ | 202.2                  |  | $                | 125.7   |      
|Operating income (loss) |  |          | 310.1   |              |   | 69.0                   |  |                  | 28.5    |      
|Total assets            |  | $        | 5,095.5 |              | $ | 3,345.6                |  | $                | 2,348.2 |      
|September 30, 2001      |  |          |         |              |   |                        |  |                  |         |      
|Operating revenues      |  | $        | 783.5   |              | $ | 195.7                  |  | $                | 93.1    |      
|Operating income (loss) |  |          | 403.7   |              |   | 59.9                   |  |                  | 16.3    |      
|Total assets            |  | $        | 6,644.6 |              | $ | 3,046.4                |  | $                | 3,157.4 |      
|
|
|September 30, 2002      |  |          |         |              |   |                        |  |                  |         |      
|Operating revenues      |  | $        | 1,479.1 |              | $ | 563.0                  |  | $                | 410.6   |      
|Operating income (loss) |  |          | 354.2   |              |   | 201.0                  |  |                  | 117.9   |      
|Total assets            |  | $        | 5,095.5 |              | $ | 3,345.6                |  | $                | 2,348.2 |      
|September 30, 2001      |  |          |         |              |   |                        |  |                  |         |      
|Operating revenues      |  | $        | 1,695.5 |              | $ | 341.4                  |  | $                | 343.8   |      
|Operating income (loss) |  |          | 628.6   |              |   | 130.9                  |  |                  | 97.2    |      
|Total assets            |  | $        | 6,644.6 |              | $ | 3,046.4                |  | $                | 3,157.4 |      

21

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NOTE 8. INVESTMENTS

The following table presents summarized financial information of the significant subsidiary investments in energy projects accounted for by the equity method. The
significant subsidiary investments include the Cogeneration Group. The Cogeneration Group consists of Kern River Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company, of
which we own 50 percent, 50 percent and 49 percent interests, respectively.

|                   |  | Three Months Ended
September 30, |       | Nine Months Ended
September 30,
|------------------ |  | -------------------------------- | ----- | -------------------------------
|
|
|Operating revenues |  | $                                | 225.6 |                                
|Operating income   |  |                                  | 120.3 |                                
|Net income         |  |                                  | 120.0 |                                

The
following table presents summarized financial information of our significant subsidiary investment in oil and gas accounted for by the equity method. The significant subsidiary is
Four Star Oil & Gas Company, in which we own 37 percent.

|                   |  | Three Months Ended
September 30, |      | Nine Months Ended
September 30,
|------------------ |  | -------------------------------- | ---- | -------------------------------
|
|
|Operating revenues |  | $                                | 50.2 |                                
|Operating income   |  |                                  | 18.9 |                                
|Net income         |  |                                  | 11.8 |                                

NOTE 9. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION

Nine Months Ended
September 30,2002

2001(Unaudited)(in millions)Cash paidInterest (net of amount capitalized)

$
299.6

$
328.3Income taxes (receipts)

$
(342.4
)
$
27.7Cash payments under plant operating leases

$
245.7

$
113.6Details of assets acquiredFair value of assets acquired

$


$
888.7Liabilities assumed





(801.3
)Net cash paid for acquisitions

$


$
87.4


NOTE 10. CHANGES IN ACCOUNTING

Statement of Financial Accounting Standard No. 133

In December 2001, the Derivative Implementation Group of the Financial Accounting Standards Board issued a revised interpretation of "Normal Purchases and
Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity," referred to as Statement No. 133 Implementation Issue Number C15. Under this revised
interpretation, our forward electricity contracts no longer qualify for the normal sales exception since we have net settlement agreements with our counter-parties. In lieu of following this exception
in which we record revenue on an accrual basis, we believe our forward sales agreements qualify as cash flow hedges. Under a cash flow hedge, we record

22

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the fair value of the forward sales agreements on our balance sheet and record the effective portion of the cash flow hedge as part of other comprehensive income. The ineffective portion of our cash
flow hedges is recorded directly in our income statement. We implemented this interpretation on April 1, 2002. We recorded assets at fair value of $11.9 million, deferred taxes of
$5.5 million and a $6.4 million increase to other comprehensive income as the cumulative effect of adoption of this interpretation.

EITF Issue No. 02-03 Related to Energy Contracts

In October 2002, the FASB Emerging Issues Task Force (commonly referred to as EITF) reached a consensus to rescind EITF No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management Activities," subject to transition positions, as part of its deliberations on Issue No. 02-03, "Recognition
and Reporting of Gains and Losses on Energy Trading Contracts," under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities,"
and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." The rescission of EITF No. 98-10 means that
energy trading and risk management activities will no longer be marked to market as trading activities, but will instead follow Statement of Financial Accounting Standards No. 133, "Accounting
for Derivatives" (SFAS No. 133). Under SFAS No. 133, each energy contract must be assessed to determine whether or not it meets the definition of a derivative subject to SFAS
No. 133. If an energy contract meets the definition of a derivative, then it would be recorded at fair value (i.e., mark-to-market), subject to permitted exceptions. If
an energy contract does not meet the definition of a derivative, then it would be recorded on an accrual basis. As a result of this new consensus, we will discontinue application of EITF
No. 98-10 for our energy trading operations for all new contracts entered into after October 25, 2002 and will instead apply SFAS No. 133 to these transactions. Under
the transition rules, we will record a cumulative change in accounting as of January 1, 2003 for any energy contracts entered into prior to October 25, 2002 that no longer qualify for
mark-to-market accounting. We are conducting a review of our existing contracts to determine the impact of this change in accounting for contracts outstanding at
October 25, 2002.

Statement of Financial Accounting Standard No. 142

Effective January 1, 2002, we 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. The statement
requires that goodwill should be tested for impairment using a two-step approach. The first step used to identify a potential impairment compares the fair value of a reporting unit to its
carrying amount, including goodwill. If the fair value of the reporting unit is less than its carrying amount, the second step of the impairment test is performed to measure the amount of the
impairment loss. The second step of the impairment test is a comparison of the implied fair value of goodwill to its carrying amount. The impairment loss is equal to the excess carrying amount of the
goodwill over the implied fair value. We completed the first step described above for each of the components of our goodwill. The fair value of the reporting units for the Contact Energy and First
Hydro operations was in excess of related book value at January 1, 2002. Accordingly, no impairment of the goodwill related to these reporting units was recorded upon adoption of this standard.
We concluded that fair value of the reporting unit related to the Citizens Power LLC acquisition was less than our book value and, accordingly, the goodwill related to this reporting unit was
impaired at January 1, 2002.

During
the third quarter of 2002, we completed the second step of the impairment test described above. Such analysis resulted in a goodwill impairment of $14 million, net of
$8.8 million of income tax benefit, associated with the Citizens Power LLC acquisition. Estimates of fair value were determined using comparable transactions. In accordance with SFAS
No. 142, this decrease to continuing operations was recorded as of January 1, 2002 as a cumulative effect of a change in accounting

23

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principle, reflected in our consolidated income statement for the nine months ended September 30, 2002.

Included
in "Restricted cash and other assets" on our consolidated balance sheet are customer contracts with a gross carrying amount of $23.9 million and accumulated amortization
of $1.1 million at September 30, 2002. The contracts have a weighted average amortization period of 20 years. For the three and nine months ended September 30, 2002, the
amortization expense was $0.3 million and $1.1 million, respectively. Based on the current amount of intangible assets subject to amortization, the estimated amortization expense for
fiscal years 2003 through 2007 is $1.4 million each year.

Changes
in the carrying amount of goodwill, by segment, for the nine months ended September 30, 2002 are as follows:

|                                                  |  | Americas |       | Asia Pacific |   | Europe and
Middle East |   | Total |      
|------------------------------------------------- |  | -------- | ----- | ------------ | - | ---------------------- | - | ----- | -----
|
|Carrying amount at December 31, 2001              |  | $        | 24.8  |              | $ | 359.5                  |   | $     | 247.4
|Impairment losses                                 |  |          | (22.8 | )            |   |                       |   |       |     
|Intangibles reclassed to other assets             |  |          |      |              |   | (24.8                  | ) |       |     
|Translation adjustments and other                 |  |          |      |              |   | 54.3                   |   |       | 19.7 
|                                                  |  |          |       |              |   |                        |   |       |      
|Carrying amount at September 30, 2002 (Unaudited) |  | $        | 2.0   |              | $ | 389.0                  |   | $     | 267.1
|                                                  |  |          |       |              |   |                        |   |       |      

The
following table sets forth what net income would have been exclusive of goodwill amortization for the three and nine months ended September 30, 2002 and September 30,
2001.

|                                            |  | Three Months Ended
September 30, |       | Nine Months Ended
September 30, |  
|------------------------------------------- |  | -------------------------------- | ----- | ------------------------------- | -
|
|
|Reported net income (loss)                  |  | $                                | 162.8 |                                 | $
|Add back: Goodwill amortization, net of tax |  |                                  |      |                                 |  
|                                            |  |                                  |       |                                 |  
|Adjusted net income (loss)                  |  | $                                | 162.8 |                                 | $
|                                            |  |                                  |       |                                 |  

Statement of Financial Accounting Standard No. 145

In April 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses
from extinguishment of debt and accounting for leases, among other things. The portion of the statement relating to the rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment
of Debt" requires that any gain or loss on extinguishment of debt that was classified as an extraordinary item that does not meet the unusual in nature and infrequent of occurrence criteria in APB
Opinion No. 30, "Reporting the Results of OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions" shall be reclassified. The standard, effective on January 1, 2003, will require us, when adopted, to reclassify as part of Income from Continuing Operations, an extraordinary gain
of $5.7 million, net of tax, recorded in December 2001. The extraordinary gain was attributable to the extinguishment of debt that was assumed by the third-party lessors in the
December 2001 Homer City sale-leaseback transaction.

24

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Statement of Financial Accounting Standard No. 146

In June 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities," which will be effective on January 1, 2003. The statement 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. We do not expect this standard to have a material impact on our consolidated
financial statements.

NOTE 11. SUBSEQUENT EVENTS

Employees at our Illinois Plants in union-represented positions are covered by collective bargaining agreements that are due to expire December 31, 2005.
These employees also had a retirement health care and other benefits plan agreement that expired on June 15, 2002. In October 2002, we reached an agreement with our union-represented
employees on a new retirement health care and other benefits plan, which extends from January 1, 2003 through June 30, 2005. We will continue to provide benefits at the same level as
those in the expired agreement until December 31, 2002.

As
described in our 2001 Annual Report on Form 10-K, we have been accounting for postretirement benefits obligations on the basis of a substantive plan under Statement
of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." A substantive plan means that we are assuming for accounting purposes that we
would provide for postretirement benefits to union-represented employees following conclusion of negotiations to replace the current benefits agreement, even though we have no legal obligation to do
so. Under the new agreement, postretirement benefits will not be provided. Accordingly, we will treat this as a plan termination under SFAS No. 106 and will record a pre-tax gain of
$70.7 million during the fourth quarter of 2002.

25

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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 our current plans and expectations and involve
risks and uncertainties which could cause actual future activities and results of operations to be materially different from those set forth in the forward-looking statements. Important factors that
could cause differences in our results of operations are set forth under "Credit Ratings" and "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 Edison Mission Energy's Annual Report on Form 10-K for the year
ended December 31, 2001.

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 Edison Mission Energy since December 31, 2001, and as compared to the third quarter and nine months ended
September 30, 2001. 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 Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2001.

Unless otherwise indicated, the information presented in this section is with respect to Edison Mission Energy and our consolidated
subsidiaries.

General

We are an independent power producer engaged in the business of owning or leasing and operating electric power generation facilities worldwide. We also conduct
price risk management and energy trading activities in power markets open to competition. Edison International is our ultimate parent company. Edison International also owns Southern California Edison
Company, one of the largest electric utilities in the United States.

As
of September 30, 2002, we owned interests in 28 domestic and 51 international operating power projects with an aggregate generating capacity of 23,918 megawatts (MW), of which
our share was 19,102 MW. At that date, one domestic and five international projects, totaling 701 MW of generating
capacity, of which our anticipated share will be approximately 350 MW, were in construction. At September 30, 2002, we had consolidated assets of $11 billion and total shareholder's
equity of $1.7 billion.

Current Developments

A number of significant developments have adversely affected independent power producers and subsidiaries of major integrated energy companies who sell a sizable
portion of their generation into the wholesale energy market (sometimes referred to as merchant generators). These developments include depressed 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, and the decline of liquidity in the energy markets as a result of tightening credit and
increasing concern about the ability of counter-parties to perform their obligations. In addition, many merchant generators and power trading firms have announced plans to improve their financial
position through asset sales, the cancellation or deferral of substantial new development, significant reductions in or elimination of trading activities, decreases in capital expenditures, including
cancellations of orders for new turbines, and reductions in operating costs.

Our Situation

Because of the 2000-2001 California power crisis, and its indirect effect on us, we began in early 2001 to shift our emphasis from the development and
acquisition of projects to focus instead on

26

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enhancing the performance of our existing projects and on maintaining credit quality. As a result, during 2001 and early 2002, we completed the sale of several non-strategic project
investments, and, during the first quarter of 2002, further reduced business development activities and undertook a related effort to reduce both corporate overhead and other expenditures across the
organization and reduce debt.

Notwithstanding
these efforts, in 2002, we have been affected by lower wholesale prices of energy and capacity, particularly at our Homer City facilities in Pennsylvania, and by the
diminished ability to enter into forward contracts for the sale of power primarily from these facilities because of the credit constraints affecting us and many of our counter-parties.

Our
Illinois Plants have been largely unaffected by these developments, because Exelon Generation is under contract to buy substantially all of the capacity of these units for the
balance of 2002. However, as permitted by the power purchase agreements, Exelon Generation has advised us that it will not purchase 2,684 MW of the capacity from our coal-fired units and
1,864 MW of capacity from our Collins Station and small peaking units for 2003 and 2004 and Exelon Generation has the further right to release an additional 3,043 MW for 2004. As a result, beginning
in 2003, the portion of our
generation to be sold into the wholesale markets will significantly increase, thereby increasing our merchant risk. See "Market Risk ExposuresIllinois Plants."

As
a result of these and other factors, Moody's downgraded our credit rating and the credit ratings of our largest subsidiary, Edison Mission Midwest Holdings, on October 1, 2002,
as shown in the following table:

|Rated Entities                                    |  | Moody's Rating
prior to Downgrade |  | Moody's Rating
after Downgrade
|------------------------------------------------- |  | --------------------------------- |  | ------------------------------
|Edison Mission Energy senior unsecured debt       |  | Baa3                              |  | Ba3                           
|Edison Mission Midwest Holdings Co. bank facility |  | Baa2                              |  | Ba2                           

In
addition, Standard & Poor's has placed our credit ratings on CreditWatch with negative implications. See "Liquidity and Capital ResourcesCredit
Ratings."

Against
this background, we have undertaken a number of actions to reduce our commitments and expenditures, thereby improving our cash flow. These actions include:



We
have also reduced our already modest non asset-backed trading activities in Boston, and focused almost exclusively on the sale of power from our facilities and related risk management
activities.

In
addition, we continue to review the possibility of sales of assets, but believe that current market conditions may inhibit our ability to obtain prices commensurate with our valuation
of those investments which we might offer for sale. For a discussion of our current financial condition, see "Liquidity and Capital Resources."

27

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Disposition of Investments in Energy Projects

During the first quarter of 2002, we completed the sales of our 50% interests in the Commonwealth Atlantic and James River projects and our 30% interest in the
Harbor project. Proceeds received from the sales were $44 million. During the second half of 2001, we recorded asset impairment charges of $32.5 million related to these projects based
on the expected sales proceeds. No gain or loss was recorded from the sale of our interests in these projects during the first quarter of 2002.

28

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RESULTS OF OPERATIONS

Operating revenues are derived from our majority-owned domestic and international entities. Equity in income from investments relates to energy projects where our
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 we have a significant influence but in
which we do not have a controlling interest. With respect to entities accounted for under the equity method, we recognize our proportional share of the income or loss of such entities.

As
an aid in understanding our results of operations, the following table summarizes revenues and operating income from our major projects (in millions):

|                    |                       |  |          | Three Months Ended September 30, |   | Nine Months Ended September 30,
|------------------- | --------------------- |  | -------- | -------------------------------- | - | -------------------------------
|
|
|
|
|Operating revenues: |                       |  |          |                                  |   |                                
|                    | Illinois Plants       |  | Americas |                                  | $ | 529.5                          
|                    | Homer City facilities |  | Americas |                                  |   | 118.0                          
|                    | First Hydro           |  | Europe   |                                  |   | 72.1                           
|                    | Big 4 projects(2)     |  | Americas |                                  |   | 69.2                           
|                    | Four Star(3)          |  | Americas |                                  |   | 3.6                            
|Operating income:   |                       |  |          |                                  |   |                                
|                    | Illinois Plants       |  | Americas |                                  | $ | 258.0                          
|                    | Homer City facilities |  | Americas |                                  |   | 29.9                           
|                    | First Hydro           |  | Europe   |                                  |   | 10.4                           
|                    | Big 4 projects(2)     |  | Americas |                                  |   | 69.2                           
|                    | Four Star(3)          |  | Americas |                                  |   | 3.4                            

---

We
operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic regions: Americas, Asia-Pacific, and Europe and
Middle East. The following discussion of our operating results is set forth by region with reference to the performance of our major projects described above.

29

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Americas

|                                                             |                          | Three Months Ended
September 30, |       | Nine Months Ended
September 30,
|------------------------------------------------------------ | ------------------------ | -------------------------------- | ----- | -------------------------------
|
|
|Operating revenues                                           |                          | $                                | 652.4 |                                
|Net gains from price risk management and energy trading      |                          |                                  | 10.2  |                                
|Equity in income from investments                            |                          |                                  | 103.8 |                                
|                                                             |                          |                                  |       |                                
|                                                             | Total operating revenues |                                  |       | 766.4                          
|Fuel and plant operations (including plant operating leases) |                          |                                  | 329.3 |                                
|Depreciation and amortization                                |                          |                                  | 36.0  |                                
|Asset impairment and other charges                           |                          |                                  | 85.9  |                                
|Administrative and general                                   |                          |                                  | 5.1   |                                
|                                                             |                          |                                  |       |                                
|                                                             | Operating income         |                                  | $     | 310.1                          
|                                                             |                          |                                  |       |                                

Operating Revenues

Operating revenues decreased $0.1 million and $64.3 million in the third quarter and nine months ended September 30, 2002, respectively,
compared to the corresponding periods of 2001. The 2002 year-to-date decrease primarily resulted from lower electric revenues from the Homer City facilities due to decreased
generation and lower energy and capacity prices. On February 10, 2002, we experienced a major unplanned outage due to a collapse of the SCR ductwork of one of the units at the Homer City
facilities, known as Unit 3. The unit was restored to operation on April 4, 2002 and is operating with the SCR bypassed. As a result of the Unit 3 SCR ductwork collapse, we
reviewed the similar structures on Units 1 and 2 and determined that as a precaution it would be appropriate to install additional reinforcement in these structures. The additional
reinforcement extended the duration of planned outages for these units, which had been scheduled to end on June 2, 2002. Unit 1 returned to service on June 28, 2002, and
Unit 2 returned to service on June 26, 2002.

Electric
power generated at the Illinois Plants is sold under power purchase agreements with Exelon Generation Company. Exelon Generation is obligated to make capacity payments for the
plants under contract and an energy payment for electricity produced by these plants. Our revenues under these power purchase agreements were $521.3 million and $486.8 million for the
three-month periods ended September 30, 2002 and 2001, respectively. This represented 48% and 45% of our consolidated operating revenues in 2002 and 2001, respectively. For the
nine-month periods ended September 30, 2002 and 2001, our revenues under these power purchase agreements were $956.8 million and $912 million, respectively. This
represented 39% and 38% of our consolidated operating revenues in the first nine months of 2002 and 2001, respectively. For more information on these power purchase agreements, including committed
capacity and energy purchases by Exelon Generation for 2003, see "Market Risk ExposuresIllinois Plants."

Due
to warmer weather during the summer months, electricity revenues generated from the Homer City facilities and the Illinois Plants are usually higher during the third quarter of each
year. In addition, our third quarter equity in income from investments in energy projects is materially higher than other quarters of the year due to higher summer pricing under contracts held by our
West Coast partnership investments.

Total
gains and losses from price risk management activities recorded at fair value under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS No. 133), were $(3.4) million and $0.6 million for the third quarter and $(3.4) million and $30.7 million for the nine months
ended September 30, 2002 and 2001, respectively. The increase in losses of $4 million and $34.1 million for the third quarter and nine months ended September 30, 2002,

30

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respectively, compared to the corresponding periods in 2001, was primarily due to realized and unrealized gains in 2001 for a gas swap purchased to hedge a portion of our gas price risk related to
our share of gas production in Four Star, an oil and gas company in which we have a minority interest and which we account for under the equity method. During the third quarter and nine months ended
September 30, 2001, we recorded gains on these gas swaps of $7.9 million and $45.9 million, respectively, due to a decrease in gas prices. During the second quarter of 2002, we
entered into hedge transactions related to the gas price risk of our investment in Four Star for 2002 with realized and unrealized losses totaling $1.3 million and $0.7 million for the
third quarter and nine months ended September 30, 2002. In addition, during the third quarter and nine months ended September 30, 2001, we recorded a
mark-to-market loss of $12.6 million and $20.8 million resulting from the change in market value of future contracts entered into with respect to a portion of our
anticipated fuel purchases through 2002 at the Illinois Plants that did not qualify for hedge accounting under SFAS No. 133.

Net
gains from energy trading activities were $13.6 million and $3.1 million for the quarters ended September 30, 2002 and 2001, respectively, and
$36.6 million and $5.5 million for the nine months ended September 30, 2002 and 2001, respectively. The increase in net gains from trading activities in the third quarter and nine
months ended September 30, 2002 of $10.5 million and $31.1 million, respectively, compared to the corresponding periods in 2001, was primarily due to gains realized on
transmission congestion contracts entered into during the third quarter of 2002 and as a result of completing the restructuring of a power sales agreement with an unaffiliated electric utility during
the first quarter of 2002. As part of the transaction, we 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, we have recorded net gains of $1.8 million and
$20.6 million for the third quarter and nine months ended September 30, 2002, respectively, attributable to their fair value in accordance with EITF 98-10, "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities" (generally referred to as mark-to-market accounting). See "Liquidity and Capital
ResourcesSubsidiary Financing Plans" for a discussion of the non-recourse debt incurred to finance the purchase of the power sales agreement.

Equity
in income from investments decreased $23.5 million and $149.1 million during the third quarter and nine months ended September 30, 2002, respectively,
compared to the same prior year periods. The 2002 decrease was primarily due to higher energy pricing during the nine-month period ended September 30, 2001.

Operating Expenses

Fuel and plant operations, including plant operating leases, increased $25.9 million and $18.8 million for the third quarter and nine months ended
September 30, 2002, respectively, compared to the corresponding periods of 2001. Fuel costs increased $31.7 million and decreased $14.6 million during the third quarter and nine
months ended September 30, 2002, respectively, compared to the same periods in 2001. The third quarter increase was due to higher fuel costs at the Illinois Plants due to increased generation.
The 2002 year-to-date decrease in fuel expense resulted from lower fuel costs at the Homer City facilities due to decreased generation in 2002, partially offset by higher fuel
costs at the Illinois Plants.

Plant
operations costs decreased $25.6 million and $21.8 million for the third quarter and nine months ended September 30, 2002, respectively, compared to the
corresponding periods of 2001. The 2002 decrease was due to a decrease in plant operations costs at the Illinois Plants primarily due to higher maintenance costs in 2001 from planned outages and costs
of additional security related to a strike at these plants during the third quarter of 2001.

31

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Plant
operating leases increased $19.8 million and $55.2 million during the third quarter and nine months ended September 30, 2002, respectively, as compared to the
corresponding periods of 2001, resulting primarily from lease costs related to the sale-leaseback commitments for the Homer City facilities. There were no comparable lease costs for the
Homer City facilities during the first nine months of 2001.

Depreciation
and amortization expense decreased $10 million and $22.1 million for the third quarter and nine months ended September 30, 2002, respectively, compared
to the same periods last year. The 2002 decrease resulted from lower depreciation expense at the Homer City facilities due to the sale-leaseback transaction for the Homer City facilities
to third-party lessors in December 2001.

Asset
impairment and other charges of $85.9 million for both the third quarter and the nine months ended September 30, 2002, consisted of $60.5 million related to
the write-off of capitalized costs associated with the termination of the turbines from Siemens Westinghouse and $25.4 million related to the write-off of capitalized
costs associated with the suspension of the Powerton Station SCR major capital environmental improvements project at the Illinois Plants. For more information on the write-off of
capitalized costs, see "Note 6. Commitments and ContingenciesCapital Expenditures."

Asset
impairments of $24.5 million for both the third quarter and the nine months ended September 30, 2001, were required to write down our investments to the estimated net
proceeds from the planned sale of the James River and Nevada Sun-Peak projects. During the third quarter of 2001, we entered into
agreements, subject to obtaining consents from third parties and other conditions precedent to closing, for the sale of our 50% interest in these projects. During the fourth quarter of 2001 and the
first quarter of 2002, we completed the sales of our 50% interests in the Nevada Sun-Peak and James River projects, respectively.

Administrative
and general expenses consist of administrative and general expenses incurred at our price risk management and energy trading operations in Boston, Massachusetts. For the
third quarter and nine months ended September 30, 2002, there were no material changes in administrative and general expenses.

Operating Income

Operating income decreased $93.6 million and $274.4 million during the third quarter and nine months ended September 30, 2002, respectively,
compared to the corresponding periods of 2001. The 2002 decrease was primarily due to lower operating income of $44.8 million for the third quarter and $141.1 million for the nine months
ended September 30, 2002 from the Homer City facilities resulting from major unplanned outages at Units 1, 2 and 3, lower U.S. energy prices affecting our investments in energy projects
and our oil and gas investments as discussed above. We have completed our investigation of the Unit 3 outage event and submitted our findings to the contractor. The contractor has completed
their preliminary investigation of the event and we are reviewing these preliminary findings. Both parties are working together to develop a suitable restoration plan to return the SCR to service with
a targeted completion date of late May 2003. We face increased emission allowance costs and possibly some loss of dispatch if the SCR is not returned to service for the 2003 NOx season
(May-September). We believe that the costs to repair the damage will be covered, for the most part, by insurance and the contractual obligations of the contractor who installed the SCR.

Illinois Postretirement Benefits Other Than Pensions

Employees at our Illinois Plants in union-represented positions are covered by collective bargaining agreements that are due to expire December 31, 2005.
These employees also had a retirement health care and other benefits plan agreement that expired on June 15, 2002. In October 2002, we reached an agreement with our union-represented
employees on a new retirement health care and other benefits

32

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plan, which extends from January 1, 2003 through June 30, 2005. We will continue to provide benefits at the same level as those in the expired agreement until December 31, 2002.

As
described in our 2001 Annual Report on Form 10-K, we have been accounting for postretirement benefits obligations on the basis of a substantive plan under Statement
of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." A substantive plan means that we are assuming for accounting purposes that we
would provide for
postretirement benefits to union-represented employees following conclusion of negotiations to replace the current benefits agreement, even though we have no legal obligation to do so. Under the new
agreement, postretirement benefits will not be provided. Accordingly, we will treat this as a plan termination under SFAS No. 106 and will record a pre-tax gain of
$70.7 million during the fourth quarter of 2002.

Asia Pacific

|                                                         |                          | Three Months Ended
September 30, |       | Nine Months Ended
September 30, |  
|-------------------------------------------------------- | ------------------------ | -------------------------------- | ----- | ------------------------------- | -
|
|
|Operating revenues                                       |                          | $                                | 192.9 |                                 | $
|Net losses from price risk management                    |                          |                                  | (1.5  | )                               |  
|Equity in income from investments                        |                          |                                  | 10.8  |                                 |  
|                                                         |                          |                                  |       |                                 |  
|                                                         | Total operating revenues |                                  |       | 202.2                           |  
|Fuel and plant operations (including transmission costs) |                          |                                  | 116.2 |                                 |  
|Depreciation and amortization                            |                          |                                  | 17.0  |                                 |  
|                                                         |                          |                                  |       |                                 |  
|                                                         | Operating income         |                                  | $     | 69.0                            |  
|                                                         |                          |                                  |       |                                 |  

Operating Revenues

Operating revenues decreased $3.2 million and increased $195.6 million during the third quarter and nine months ended September 30, 2002,
respectively, compared to the corresponding periods of 2001. The 2002 third quarter decrease was primarily due to lower electric revenues from Contact Energy as a result of lower wholesale electricity
prices in New Zealand caused by less favorable market conditions in 2002 partially offset by higher retail electricity volumes in 2002. The decrease was partially offset by higher electric revenues
from the Loy Yang B and Valley Power Peaker plants in Australia. We had no comparable results for the Valley Power Peaker project in 2001. The 2002 year-to-date increase was
primarily due to consolidating Contact Energy operating revenues as a result of our increase in ownership to 51.2% majority-control in the company, effective June 1, 2001.

Net
losses from price risk management activities recorded at fair value decreased $0.3 million and $0.4 million for the third quarter and nine months ended
September 30, 2002, respectively, compared to the corresponding periods of 2001. The 2002 losses primarily represent the ineffective portion of a long-term contract with the State
Electricity Commission of Victoria entered into by the Loy Yang B plant, which is a derivative that qualified as a cash flow hedge under SFAS No. 133. See "Note 3.
Accumulated Other Comprehensive Income (Loss)," for further discussion. The 2001 losses primarily resulted from the change in the market value of interest rate swaps and options that did not qualify
for hedge accounting under SFAS No. 133, partially offset by gains representing the ineffective portion of the Loy Yang B long-term contract.

Equity
in income from investments increased $9.4 million and $25.6 million during the third quarter and nine months ended September 30, 2002, respectively, compared
to the same prior year periods. The 2002 increase is primarily due to an increase in our share of income from the Paiton project of $30.1 million. Beginning January 1, 2002, Paiton
Energy recorded revenue in accordance with

33

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the Binding Term Sheet, which is described in more detail under "Note 6. Commitments and ContingenciesContingenciesPaiton." Revenue recognized under the
Binding Term Sheet is comprised of capacity payments (based on the availability of the power plant) and energy payments (based on electricity generated). Recognition of revenue on the basis of the
Binding Term Sheet resulted in a net profit by Paiton Energy for the nine months ended September 30, 2002. Prior to the execution of the
Binding Term Sheet, we assumed the lower end of a range of expected outcomes of negotiations of a revised power purchase agreement, which resulted in no recognition of income during the nine months
ended September 30, 2001. Partially offsetting this increase in 2002 was a decrease in equity in earnings of Contact Energy, which was accounted for on the equity method of accounting prior to
our acquisition of a controlling interest in the company in June 2001.

Operating Expenses

Fuel and plant operations increased $0.6 million and $140.1 million for the third quarter and nine months ended September 30, 2002,
respectively, compared to the corresponding periods of 2001. The 2002 year-to-date increase was primarily due to consolidating Contact Energy operating expenses, effective
June 1, 2001.

Depreciation
and amortization expense decreased $3.2 million and increased $11.4 million during the third quarter and nine months ended September 30, 2002,
respectively, compared to the corresponding periods of 2001. The 2002 third quarter decrease was primarily due to lower amortization expense from Contact Energy as a result of adoption of SFAS
No. 142, effective January 1, 2002. The 2002 year-to-date increase primarily reflects the consolidation of Contact Energy depreciation and amortization expenses,
effective June 1, 2001.

Operating Income

Operating income increased $9.1 million and $70.1 million during the third quarter and nine months ended September 30, 2002, respectively,
compared to the corresponding periods of 2001. The 2002 year-to-date increase was primarily due to consolidating Contact Energy's results of operations, effective
June 1, 2001, increased profitability of our Loy Yang B and Valley Power Peaker projects from higher energy prices, and higher equity in income from the Paiton project discussed above.

Europe and Middle East(1)

|                                              |                          | Three Months Ended
September 30, |       | Nine Months Ended
September 30,
|--------------------------------------------- | ------------------------ | -------------------------------- | ----- | -------------------------------
|
|
|Operating revenues                            |                          | $                                | 124.6 |                                
|Net gains (losses) from price risk management |                          |                                  | (4.0  | )                              
|Equity in income from investments             |                          |                                  | 5.1   |                                
|                                              |                          |                                  |       |                                
|                                              | Total operating revenues |                                  |       | 125.7                          
|Fuel and plant operations                     |                          |                                  | 87.4  |                                
|Depreciation and amortization                 |                          |                                  | 9.8   |                                
|                                              |                          |                                  |       |                                
|                                              | Operating income         |                                  | $     | 28.5                           
|                                              |                          |                                  |       |                                

---

34

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Operating Revenues

Operating revenues increased $39.4 million and $49.9 million for the third quarter and nine months ended September 30, 2002, respectively,
compared to the corresponding periods of 2001. The 2002 increase resulted primarily from higher electric revenues from the First Hydro plant due to increased volumes of power sales and higher
ancillary services revenues during the first nine months of 2002, compared to the same prior year period. On March 27, 2001, the United Kingdom pool pricing system was replaced with a bilateral
physical trading system referred to as the new electricity trading arrangements, generally referred to as NETA. The new electricity trading arrangements are described in further detail under
"Market Risk ExposuresUnited Kingdom." As a result of the bilateral market under the new electricity trading arrangements, First Hydro has entered into purchase and sales
contracts covering greater volumes of power to optimize the timing of generation from First Hydro's pumped storage plants. The First Hydro plant is expected to provide for higher electric revenues
during the winter months.

Net
gains (losses) from price risk management activities decreased $8.5 million and $3.4 million for the third quarter and nine months ended September 30, 2002,
respectively, compared to the corresponding periods of 2001. The 2002 gains (losses) primarily represent the change in market value of long-term commodity contracts entered into by the
First Hydro plant for the purchase and sale of electricity that were recorded at fair value under SFAS No. 133 with changes in fair value recorded through the income statement, effective
July 1, 2001.

Equity
in income from investments increased $1.7 million and $20.3 million during the third quarter and nine months ended September 30, 2002, respectively, compared
to the same prior year periods. The 2002 increase was due to higher profitability of our interest in the ISAB project resulting from increased generation and settlement of an insurance claim. During
the first half of 2001, we recorded losses from this project.

Operating Expenses

Fuel, including purchased power, and plant operations increased $18.7 million and $50.5 million for the third quarter and nine months ended
September 30, 2002, respectively, compared to the corresponding periods of 2001. The 2002 increase was primarily due to increased volumes of power purchases, partially offset by lower plant
operations costs at the First Hydro plant. We have reduced current
operational costs in light of the low value of power in the United Kingdom market and have included the temporary suspension of service of units at both of the plants' power stations and a reduction
in plant maintenance costs. The increase in power purchase costs reflects the changes under the new electricity trading arrangements, whereby First Hydro has purchased electricity to meet sales
commitments when it was more cost-effective to purchase than to generate electricity, thus reducing the need for physical pumping or generating. In addition, due to the new trading
arrangements, some costs previously paid by suppliers now are being paid by generators, and all market participants are being charged imbalance costs when their metered position differs from their
contracted position. The new electricity trading arrangements are described in further detail under "Market Risk ExposuresUnited Kingdom."

Operating Income

Operating income increased $12.2 million and $20.7 million during the third quarter and nine months ended September 30, 2002, respectively,
compared to the same periods of 2001. The 2002 third quarter increase was primarily due to improved profitability from the First Hydro project due to the cost saving measures implemented during 2002
and the commercial strategy adopted for the placement of the First Hydro power and services in the market. The 2002 year-to-date increase was primarily due to the increase in
equity in income from investments discussed above.

35

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Corporate/Other

|                                              |                | Three Months Ended
September 30, |      | Nine Months Ended
September 30, |  
|--------------------------------------------- | -------------- | -------------------------------- | ---- | ------------------------------- | -
|
|
|Revenues:                                     |                |                                  |      |                                 |  
|Net gains (losses) from price risk management |                | $                                |     |                                 | $
|Expenses:                                     |                |                                  |      |                                 |  
|Depreciation and amortization                 |                |                                  | 3.1  |                                 |  
|Long-term incentive compensation              |                |                                  | (3.3 | )                               |  
|Administrative and general                    |                |                                  | 30.0 |                                 |  
|                                              |                |                                  |      |                                 |  
|                                              | Operating loss |                                  | $    | (29.8                           | )
|                                              |                |                                  |      |                                 |  

Net
gains (losses) from price risk management activities recorded at fair value decreased $1 million and $4.1 million for the third quarter and nine months ended
September 30, 2002, respectively, compared to the corresponding periods of 2001. The losses primarily resulted from the change in market value of our interest rate swaps with respect to our
$100 million senior notes that did not qualify for hedge accounting under SFAS No. 133, which terminated in June 2002.

Long-term
incentive compensation expense consists of charges related to our terminated phantom option plan. Compensation expense recorded relates to the annual vesting of
benefits and interest
earned on deferred payments. During the nine months ended September 30, 2002 and 2001, adjustments were made to reflect the decrease in market value of stock equivalent units.

Administrative
and general expenses decreased $5.4 million and increased $6.3 million during the third quarter and nine months ended September 30, 2002,
respectively, compared to the corresponding periods of 2001. The 2002 third quarter decrease was primarily due to a refund of property insurance premiums from a captive insurance subsidiary of Edison
International and lower business development costs. The 2002 year-to-date increase was primarily due to a pretax charge of approximately $4.3 million
($4.1 million was against first quarter earnings) for severance and other related costs. The charge resulted from a series of actions undertaken by us to reduce administrative and general
operating costs, including reductions in management and administrative personnel.

Other Income (Expense)

Interest and other income decreased $6 million and $21.8 million for the third quarter and nine months ended September 30, 2002,
respectively, compared to the corresponding periods of 2001. The 2002 decrease was primarily due to lower interest income and foreign exchange losses from intercompany loans.

Gains
on sale of assets were $41.9 million and $45.5 million for the third quarter and nine months ended September 30, 2001, respectively. Gains on the sale of
assets included:

Project

Net Proceeds

Ownership
Interest Sold

Date of SaleSaguaro

$
67.0

50
%
September 20, 2001Hopewell


26.5

25
%
June 29, 2001


Interest
expense decreased $40.2 million and $78.6 million for the third quarter and nine months ended September 30, 2002, respectively, compared to the same prior
year periods. The 2002 decrease was due to a combination of the following: a reduction in corporate debt from the proceeds of the sale-leaseback of the Homer City facilities in
December 2001 and lower borrowings combined with lower interest rates on variable rate debt tied to LIBOR.

36

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Provision (Benefit) for Income Taxes

During the nine months ended September 30, 2002, we calculated an effective tax provision rate (before deduction of minority interest) of 41% based on
projected income for the year and related income taxes (excluding the additional tax benefits discussed below), compared to the annual effective tax provision rate for the first nine months of 2001 of
45%. The decrease in the annual effective rate is primarily due to increased earnings from taxable unconsolidated affiliates (and therefore not included in our consolidated tax provision) and is
partially offset by an expected decrease in anticipated income from operations in the United Kingdom.

During
the third quarter of 2002, we recorded additional state tax benefits, net of federal income taxes, of $26.3 million resulting from changes in estimates of the 2001 and 2002
tax-allocation calculation completed by Edison International. Under the tax-allocation agreement, our current state tax benefit is generally determined by using Edison
International's combined state tax liability and calculating the difference between including and excluding Edison Mission Energy's taxable income or losses and state apportionment factors. During the
third quarter of 2002, Edison International substantially completed preparation of its 2001 combined state income tax returns and changed its 2002 estimated state income tax projection. We expect that
approximately $8.7 million of these additional benefits will not be paid until 2004.

Edison
International received a notice on August 7, 2002, from the Internal Revenue Service (IRS) asserting deficiencies in Edison Mission Energy's federal corporation income
taxes for its 1994 to 1996 tax years. Edison International filed a timely protest to this notice. We believe that we have meritorious legal defenses to those deficiencies and believe that the ultimate
outcome of this matter will not result in a material impact on our consolidated results of operations or financial position.

We
are, and may in the future be, under examination by tax authorities in varying tax jurisdictions with respect to positions we take in connection with the filing of our 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 our opinion, it is unlikely that
the resolution of any such matters will have a material adverse effect upon our financial condition or results of operations.

Minority Interest

Minority interest expense decreased $3.6 million and increased $5 million during the third quarter and nine months ended September 30, 2002,
respectively, compared to the corresponding periods of 2001. The 2002 third quarter decrease was primarily due to lower profitability from Contact Energy in 2002. The 2002
year-to-date increase was due to accounting for Contact Energy on a consolidated basis, effective June 1, 2001, due to the purchase of additional shares of Contact
Energy that increased our ownership interest from 42.6% to a controlling interest of 51.2%.

Discontinued Operations

As a result of the change in the prices of power in the United Kingdom and the anticipated negative impacts of such changes on earnings and cash flow, we offered
for sale through a competitive bidding process the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. On December 21, 2001, we completed the sale
of the power plants 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. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. Net proceeds from the sales of £643 million were used to repay
borrowings outstanding under the existing debt facility related to the acquisition of the power plants. We recorded an after tax loss during 2001 of $1.1 billion related to the loss on disposal
of these assets. In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal

37

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of Long-Lived Assets," the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements.

During
the second quarter of 2002, we recorded income of $3.1 million from discontinued operations primarily related to an insurance recovery from claims filed prior to the sale
of the power plants.

Effective
January 1, 2001, we recorded a $5.8 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting
for derivatives. The majority of our activities related to the Ferrybridge and Fiddler's Ferry power plants did not qualify for either the normal purchases and sales exception or as cash flow hedges
under SFAS No. 133. We could not conclude, based on information available at January 1, 2001, that the timing of generation from these power plants met the probable requirement for a
specific forecasted transaction under SFAS No. 133. Accordingly, the majority of these contracts were recorded at fair value with subsequent changes in fair value recorded through the income
statement.

Cumulative Effect of Change in Accounting Principle

Accounting for Derivatives and SFAS No. 133

Our primary market risk exposures arise from changes in electricity and fuel prices, interest rates and fluctuations in foreign currency exchange rates. We manage
these risks in part by using derivative financial instruments in accordance with established policies and procedures. Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that derivative instruments be
recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. SFAS No. 133 also requires that changes in the derivative's fair value
be recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value
are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized
in earnings.

Effective
January 1, 2001, we recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. This exception applies to
physical sales and purchases of power or fuel where it is probable that physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and the
documentation requirements of SFAS No. 133 are met.

On
January 1, 2001, we recorded a $0.2 million, after tax, increase to income from continuing operations and a $230.2 million, after tax, decrease to other
comprehensive income as the cumulative effect of the adoption of SFAS No. 133. See Note 2 on page 96 in our 2001 Annual Report on Form 10-K for further
discussion of adoption of SFAS No. 133. Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133
Implementation Issue Number C15 modified the normal sales and purchases exception to include electricity contracts which include terms that require physical delivery by the seller in quantities that
are expected to be sold in the normal course of business. This modification had two significant impacts:



38

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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. We recorded a net gain (loss) of approximately $(2.2) million and $0.5 million during the third quarter of 2002 and 2001, respectively,
and a net gain (loss) of approximately $(2.4) million and $2.2 million for the nine-month periods of 2002 and 2001, respectively, representing the amount of cash flow hedges'
ineffectiveness, reflected in net gains (losses) from price risk management and energy trading in our consolidated income statement.

Discussion of Initial Adoption of SFAS No. 142

During the third quarter of 2002, we completed the steps necessary for the adoption of Statement of Financial Accounting Standards No. 142, "Goodwill and
Other Intangible Assets." We concluded that the goodwill related to the Citizens Power LLC acquisition was impaired as discussed under "New Accounting Standards." Retroactive to
January 1, 2002, we recorded a $14 million, after tax, decrease to income from continuing operations as the cumulative effect of the adoption of SFAS No. 142.

39

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LIQUIDITY AND CAPITAL RESOURCES

Credit Ratings

On October 1, 2002, Moody's downgraded our senior unsecured rating to Ba3 (below investment grade) from Baa3 (investment grade), and the ratings of our
wholly-owned indirect subsidiaries, Edison Mission Midwest Holdings Co. (bank facility to Ba2 from Baa2) and Midwest Generation, LLC (lessor bonds to Ba3 from Baa3). The ratings remain
under review for possible further downgrade. On October 10, 2002, Standard & Poor's placed the "BBB-" corporate ratings of Edison Mission Energy, Edison Mission Midwest
Holdings Co., and Edison Mission Marketing & Trading Inc. on CreditWatch with negative implications.

These
ratings actions did not trigger any defaults under our credit facilities or those of the other affected entities; however, the changed ratings will increase the borrowing costs
under certain of those facilities. For interest payments on our corporate credit facility, the applicable margin as determined by our long-term credit ratings increased for
Tranche A (to LIBOR + 3.625% from LIBOR + 2.375%) and Tranche B (to LIBOR + 3.50% from LIBOR + 2.25%). In addition to the interest
payments, the facility fee as determined by our long-term credit ratings increased for Tranche A (to 0.875% from 0.625%) and Tranche B (to 1.00% from 0.75%). We estimate our
annual interest and lease costs will increase by $36.7 million as a result of the downgrade of our credit rating based on existing debt and lease agreements.

As
a result of these rating actions, we have:



Moreover,
as a result of these ratings actions, we could be required by market practice and contract to provide collateral for our United Kingdom trading activities. To this end, our
subsidiary, Edison Mission Operation and Maintenance Limited, has obtained a cash collateralized credit facility in the amount of £17 million, under which letters of credit totaling
£11.4 million have been issued as of October 17, 2002. We also anticipate that sales of power from our Illinois Plants, Homer City facilities and First Hydro plants in the
United Kingdom may require additional credit support over the next twelve months, 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 our risk management and trading activities. We currently project the potential working capital to support our
price risk management and trading activity to be between $100 million and $200 million from time to time over the next twelve months.

Downgrade of Edison Mission Midwest Holdings

As a result of the downgrade of Edison Mission Midwest Holdings below investment grade, provisions in the agreements binding on Edison Mission Midwest Holdings
and Midwest Generation will limit the ability of Edison Mission Midwest Holdings to use excess cash flow to make distributions to us. 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

40

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under the applicable financing agreements. The currently applicable provisions are those set forth in the same row as the Moody's rating "Ba2."

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% free cash trapped until six month debt service reserve is fundedBB

Ba2

275

100% of free cash trappedBB-

Ba3

325

100% of free cash trappedB+

B1

325

100% cash sweep by lenders to repay debt (i.e., 100% of free cash trapped and used to repay debt)


As
part of the sale-leaseback of the Powerton and Joliet power stations, Midwest Generation loaned the proceeds ($1.367 billion) to Edison Mission Energy in exchange
for promissory notes in the same aggregate amount. Debt service payments by Edison Mission Energy on the promissory notes are used by Midwest Generation to meet its payment obligations under these
leases. Furthermore, Edison Mission Energy has guaranteed the lease obligations of Midwest Generation under these leases. Edison Mission Energy's obligations under the promissory notes payable to
Midwest Generation are general obligations of Edison Mission Energy and are not contingent upon receiving distributions from Edison Mission Midwest Holdings. See "Historical Distributions
Received by Edison Mission EnergyEdison Mission Midwest Holdings (Illinois Plants)" for a discussion of implications for the Powerton and Joliet leases.

As
a result of the downgrade of our subsidiary, Edison Mission Midwest Holdings, to Ba2, provisions in the agreements binding on Edison Mission Midwest Holdings require it to deposit
each quarter 100% of its defined excess cash flow into a cash flow recapture account held and maintained by the collateral agent. On October 31, 2002, Edison Mission Midwest Holdings deposited
$50 million into the cash flow recapture account in accordance with these provisions. Edison Mission Midwest Holdings will be required to make deposits into the cash flow recapture account at
the end of each such quarter in an amount equal to that quarter's excess cash flow. 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.

Possible Downgrade of Edison Mission Marketing & Trading

Pursuant to the Homer City sale-leaseback documents, a downgrade of Edison Mission Marketing & Trading to below investment grade would restrict
the ability of EME Homer City Generation to sell forward the output of the Homer City facilities. Under the sale-leaseback documents, EME Homer City Generation may only engage in permitted
trading activities as defined in the documents. These documents include a requirement that the counter-party to such transactions, and EME Homer City Generation, if acting as seller to an unaffiliated
third party, be investment grade. We currently sell all of the output from the Homer City facilities through Edison Mission Marketing & Trading, and EME Homer City Generation is not rated.
Therefore, in order for us to continue to sell forward the output of the Homer City facilities in the event of a downgrade in Edison Mission Marketing & Trading's credit, either: (1) we
must obtain a waiver from the sale-leaseback owner participant to permit EME Homer City Generation 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 investment grade requirements of the sale-leaseback documents. We have
obtained a consent from the sale-leaseback owner participant that will allow EME Homer City Generation to enter into limited amounts of such sales, under specified conditions, through

41

---

September 25, 2003. We are permitted to sell the output of the Homer City facilities into the Pennsylvania-New Jersey-Maryland Power Pool (PJM) at any time. See
"Market RisksHomer City Facilities."

Corporate Liquidity

We have a $486.7 million corporate credit facility which includes a one-year $275 million component, Tranche A, that expires on
September 16, 2003 and a three-year $211.7 million component, Tranche B, that expires on September 17, 2004. At September 30, 2002, we had borrowing capacity
under this facility of $416.5 million and corporate cash and cash equivalents of $67.2 million. We plan to utilize the corporate credit facilities to provide credit support for our
marketing and trading operations and fund corporate expenses as necessary depending on the timing and amount of distributions from our subsidiaries. During the first quarter of 2002, cash flow
included distributions from our investments in partnerships made subsequent to their receipt of payments of past due accounts receivable from Southern California Edison on March 1, 2002. Total
amounts paid to these partnerships by Southern California Edison were $415 million, of which our share was $206.2 million. In addition, we received $368 million in
tax-allocation payments from our ultimate parent company. These and cash distributions from our subsidiaries represent our major source of cash to meet our cash requirements. The timing
and amount of distributions from our subsidiaries may be affected by many factors beyond our control. See "Management's Discussion and Analysis of Results of Operations and Financial
ConditionRisk Factors" included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2001. Also see
"Historical Distributions Received by Edison Mission EnergyRestricted Assets of Subsidiaries." In addition, the timing and amount of tax-allocation payments are
dependent on
the consolidated taxable income of Edison International and its subsidiaries. See "Intercompany Tax-Allocation Payments."

In
September 2002, we amended Tranche A of our corporate credit facility to extend the expiration period to September 16, 2003 and to reduce the amount available
from $538.3 million to $275 million. Tranche B of the corporate credit facility in the amount of $211.7 million expires on September 17, 2004. The credit facility
provides credit available in the form of cash advances or letters of credit. At September 30, 2002, there were no cash advances outstanding under either Tranche and $70.1 million of
letters of credit outstanding under Tranche B. In addition to the interest payments, we pay a facility fee as determined by our long-term credit ratings (0.625% and 0.75% at
September 30, 2002 for Tranche A and Tranche B, respectively) on the entire credit facility independent of the level of borrowings.

As
part of the amendment to our credit agreement, we agreed to utilize, in lieu of the interest coverage ratio that is included in our articles of incorporation and bylaws, an interest
coverage ratio that is based on cash received by us, including tax-allocation payments, cash disbursements and interest paid. At September 30, 2002, we met this new interest
coverage ratio. The interest coverage ratio in our articles of incorporation and bylaws remains relevant for determining our ability to make distributions. See "Interest Coverage Ratio."

42

---

Discussion of Historical Cash Flow

Cash Flows From Operating Activities

Net cash provided by (used in) operating activities:

Nine Months Ended
September 30,2002

2001(Unaudited)
(in millions)Continuing operations

$
568.4

$
92.1Discontinued operations


36.0


(58.2
)$
604.4

$
33.9


The
higher operating cash flow from continuing operations in the first three quarters of 2002, compared to 2001, reflects higher distributions from energy projects. In March 2002,
we received distributions from our investments in partnerships subsequent to their receipt of payments of past due accounts receivable from Southern California Edison. Lower distributions from energy
projects during 2001 primarily resulted from the delay in payments from the California utilities to our investments in California qualifying facilities. In addition, we received $368 million in
tax-allocation payments from Edison International during the first nine months of 2002. 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 three quarters of 2002 was also due to the timing of cash payables related to working
capital items. Net working capital at September 30, 2002 was $715.4 million compared to $324.6 million at December 31, 2001.

Cash
provided by operating activities from discontinued operations in 2002 reflects the settlement of working capital items from the Ferrybridge and Fiddler's Ferry power plants during
the first three quarters of 2002.

Cash Flows From Financing Activities

Net cash provided by (used in) financing activities:

Nine Months Ended
September 30,2002

2001(Unaudited)
(in millions)Continuing operations

$
(205.1
)
$
329.2Discontinued operations





(201.5
)$
(205.1
)
$
127.7


Cash
used in financing activities from continuing operations during the first three quarters of 2002 consisted of payment of $100 million of senior notes that matured, net
payments of $80 million on our $487 million corporate credit facility, $44 million related to debt service payments of one of our subsidiaries, and payments of $86 million
from our Coal and Capex facility. In addition, a wholly-owned subsidiary borrowed $84 million under a note purchase agreement in January 2002. For further discussion of the note purchase
agreement, see "Subsidiary Financing Plans." We also received $54 million from a swap agreement with a bank related to lease payments with our Homer City facilities. As of
September 30, 2002, we had recourse debt of $1.9 billion, with an additional $4.1 billion of non-recourse debt (debt which is recourse to specific assets or
subsidiaries, but not to Edison Mission Energy) on our consolidated balance sheet.

43

---

Cash
provided by financing activities from continuing operations during the first three quarters of 2001 consisted of issuances under our corporate credit facilities, $600 million
from the issuance of 9.875% senior notes in April 2001, due in 2011 and $400 million from the issuance of 10% senior notes in August 2001, due in 2008. In addition, dividends
totaling $65 million and $32.5 million were paid to The Mission Group and Mission Energy Holding Company, respectively, and ultimately $96.5 million was paid to Edison
International, our ultimate parent company.

Cash
used in financing activities from discontinued operations during the first three quarters of 2001 was primarily related to the repayment of a loan from Edison Capital, an affiliate.

Cash Flows From Investing Activities

Net cash used in investing activities:

Nine Months Ended
September 30,2002

2001(Unaudited)
(in millions)Continuing operations

$
(120.6
)
$
(331.8
)Discontinued operations





(30.5
)$
(120.6
)
$
(362.3
)


Cash
used in investing activities from continuing operations during the first three quarters of 2002 included $80.1 million paid for the purchase of a power sales agreement held
by a third party. We invested $516.5 million in the first three quarters of 2002 in new plant and equipment principally related to the Valley Power Peaker project in Australia, the Illinois
Plants, the Homer City facilities, and payments related to three turbines to Siemens Westinghouse. Also, included in capital expenditures during the first three quarters of 2002 were payments for
three turbines purchased under the Edison Mission Energy Master Turbine Lease with funds from restricted cash of $61.1 million, which reduced our restricted cash. In addition,
$25 million of restricted cash was used to satisfy our obligation related to the termination of the Edison Mission Energy Master Turbine Lease, thereby reducing our restricted cash account. In
addition, included in capital expenditures during the first nine months of 2002 was a $300 million payment for the Illinois peaker power units that were subject to a lease with
$255 million received as a repayment of the note receivable held by us. Through the first three quarters of 2002, $18.3 million was paid in equity contributions for Phase II of
the Sunrise project. We received proceeds of $44 million from the sales of our 50% interests in the Commonwealth Atlantic and James River projects and our 30% interest in the Harbor project
during the first quarter of 2002. In addition, we 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. Restricted cash totaling $53 million was used to meet our lease payment obligations.

Cash
used in investing activities from continuing operations during the first three quarters of 2001 included cash used by us for equity contributions totaling approximately
$134 million through September 30, 2001 to meet capital calls by partnerships that were owed money by Southern California Edison and Pacific Gas and Electric, following the failure by
those entities to pay amounts due for power sold under those agreements. Southern California Edison repaid all outstanding amounts on March 1, 2002, and Pacific Gas and Electric is making
payments against defaulted amounts on a schedule that should allow for payment in full by the end of the first quarter of 2003. Through the first three quarters of 2001, $3.8 million was paid
towards the purchase price and $1.5 million in equity contributions for the Italian Wind projects, $20 million was paid for the purchase of the 50% interest in the CBK project and
$59.5 million was paid for the purchase of additional shares in Contact Energy. In

44

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June 2001, we also completed the sale of a 50% interest in the Sunrise project to Texaco for $84 million. We invested $170 million during the first three quarters of 2001 in new
plant equipment principally related to the Homer City facilities and Illinois Plants.

Historical Distributions Received By Edison Mission Energy

The following table is presented as an aid in understanding the cash flow of Edison Mission Energy 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 nine months of each year are not necessarily
indicative of annual distributions due to the seasonal fluctuations in our business.

Nine Months Ended
September 30,2002

2001(Unaudited)
(in millions)Distributions from Consolidated Operating Projects:Edison Mission Midwest Holdings (Illinois Plants)

$


$
EME Homer City Generation L.P. (Homer City facilities)





43.7First Hydro Holdings





51.6Holding companies of other consolidated operating projects


21.2


0.3Distributions from Non-Consolidated Operating Projects:Distributions from Big 4 projects(1)


111.8


128.8Distributions from Four Star Oil and Gas Company


21.0


56.6Distributions from other non-consolidated operating projects


66.3


18.7Total Distributions

$
220.3

$
299.7


---

Changes
in distributions between the nine-month periods were due to:



45

---



Restricted Assets of Our Subsidiaries

Each of our direct or indirect subsidiaries is organized as a legal entity separate and apart from us and our other subsidiaries. Assets of our subsidiaries are
not available to satisfy our obligations or the obligations of any of our 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 us or to our affiliate. Set forth below is a description
of covenants binding our principal subsidiaries that may restrict the ability of those entities to make distributions to Edison Mission Energy directly or indirectly through the other holding
companies owned by Edison Mission Energy:



Edison Mission Midwest Holdings is the borrower under a $1.869 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 LLC, a wholly-owned subsidiary of Edison Mission Midwest
Holdings, owns, leases or 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 to make a distribution from Edison Mission Midwest Holdings to Edison Mission Energy, Edison Mission Midwest Holdings and
Midwest Generation must be in compliance with the covenants specified in these agreements, including maintaining a minimum credit rating. Due to the downgrade of the credit rating of Edison Mission
Midwest Holdings, no distributions can currently be made by Edison Mission Midwest Holdings to Edison Mission Energy 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. We expect that revenues for 2003 from Exelon Generation will represent
50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenues. Failure to meet such historical debt service coverage ratio is an event of default under the credit agreement and
Collins lease agreements, which, upon a vote by a majority of the lenders to accelerate the due date of the obligations of Edison Mission Midwest Holdings or associated with the Collins lease, may
result in an event of default under
the Powerton and Joliet leases. At September 30, 2002, we met the historical debt service coverage ratio.

There
are no restrictions on the ability of Midwest Generation to make payments on the outstanding intercompany loans from its affiliate Edison Mission Overseas (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 requirements measured on the date of
distribution:



46

---



At
September 30, 2002, we met the above financial performance measures. However, as a result of lower wholesale prices of electricity and capacity and the adverse impact of the
plant outages, we do not expect EME Homer City Generation to have funds available for distributions to us for the remainder of 2002.



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 the following interest coverage ratio:



First
Hydro's interest coverage ratio must also exceed a minimum default threshold included in the Guaranteed Secured Bonds. When measured for the twelve-month period ended
June 30, 2002, First Hydro's interest coverage ratio was above the default threshold but below the minimum required to permit distributions. We believe that if market and trading conditions
experienced thus far in 2002 are sustained for the balance of the year, First Hydro's interest coverage ratio will also be above the distribution threshold when measured for the twelve-month period
ended December 31, 2002. Compliance by First Hydro with these and other requirements of its bond financing documents is subject, however, to market conditions for the sale of energy and
ancillary services.



Our subsidiaries, which we refer to as the "Guarantors," that hold our 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 ownership interests in 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 us if Edison Mission 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:



47

---



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. At September 30, 2002, there were no restrictions under these covenants on our
ability to receive distributions. Although the credit ratings of Edison Mission Energy Funding's notes and bonds were recently subject to a downgrade to below investment grade, this will have no
effect on the ability of the Guarantors to make distributions to us.

Other Matters Related to Distributions from Subsidiaries or Affiliates

Paiton ProjectPaiton Energy and PT PLN have completed negotiations on an amendment to the power purchase agreement which
incorporates the terms and conditions of the Binding Term Sheet into the power purchase agreement. While the project lenders have approved the Binding Term Sheet, Paiton Energy has yet to obtain
approval of the amendment to the power purchase agreement by the project lenders. Paiton Energy and its government agency lenders have agreed to Summary Terms and Conditions for Debt Restructuring of
Paiton Energy, which terms and conditions have been approved by the commercial bank lenders to the project. In addition, Paiton Energy must seek approval of the debt restructuring from its bond
holders. Distributions from the project will not occur until restructuring of the senior debt has been completed, and in any case, are not likely to commence until at least 2006.

Lakeland ProjectThe combination of the introduction of the New Electricity Trading Arrangements (replacing the "pool" system
of electricity sales in the United Kingdom) and the so-called Transfer Scheme (separating the supply and distribution businesses in the United Kingdom) required material amendment to
Lakeland's power sales agreement and related documents. By October 2002, agreement had been reached with Norweb Energi Ltd (the counter-party under the Lakeland power sales agreement and
an indirect subsidiary of TXU Europe) and all other relevant parties as to the form of the necessary amendments, but the documentation to implement this agreement was awaiting actual signature and has
not yet been signed.

On
October 14, 2002, TXU Corp., the U.S. parent company of TXU Europe, announced that it would not provide additional funding for its European business and was considering selling
all or a portion of this business. On October 21, 2002, TXU Corp. announced the sale by its indirect subsidiary, TXU (United Kingdom) Ltd. of all its retail customer contracts in the
United Kingdom. Concurrently, TXU
announced its intention to renegotiate certain power sales agreements, including the Lakeland power sales agreement, as part of an effort to restructure its operations and preserve creditor value. TXU
further indicated that failure to renegotiate these agreements or otherwise to restructure its operations could result in the equivalent of bankruptcy in the United Kingdom for one or more of TXU's
subsidiaries, including possibly Norweb Energi Ltd.

Currently,
we continue to deliver power under the Lakeland power sales agreement and Norweb Energi Ltd has made all payments. We cannot determine, however, the outcome of TXU's
restructuring activities in Europe, nor the effect of such activities upon the Lakeland power sales agreement. If the power sales agreement is terminated, we could operate the Lakeland project as a
merchant plant, but because of current depressed power prices in the United Kingdom market, we may not be able to operate the plant profitably in the near term. Although cash is held by the project,
we do not anticipate any distributions unless and until the uncertainties surrounding the power sales agreement are resolved. Further, during the fourth quarter, we will complete an asset impairment
evaluation taking into

48

---

consideration continuing developments with respect to the power sales agreement. The condensed financial position of the Lakeland project at September 30, 2002 is set forth below:

September 30,
2002(Unaudited)
(in millions)Cash

$
32.4Property, plant and equipment


138.0Other assets


13.8Total assets

$
184.2Accounts payable

$
12.0Debt


72.2Deferred taxes


32.1Equity


67.9Total liabilities and equity

$
184.2


ISAB ProjectWe own a 49% interest in the ISAB project in Italy. The project has recently renewed its insurance coverage
which, because of the events of September 11, 2001 and the resulting constraints in the insurance industry, is not compliant with the insurance requirements set out in the facility loan
documentation. While we believe the coverage obtained is the maximum available at the current time at reasonable commercial rates, deviations from the specified coverages nevertheless require approval
of the lending group. Additionally, our partner in the project wishes to transfer its ownership of certain of the project-related assets to an affiliate company and is seeking lender approval for
this. Finally, the project is required to provide the lending group periodically with a long-term forecast which is used to determine the loan life coverage ratio based on, among other
things, a set of technical assumptions for the project which must be approved by the technical adviser to the lenders. In part because of the overall group-wide cost analysis being
undertaken by us, preparation of the technical assumptions has been delayed beyond its due date, thereby delaying preparation of the forecast and the calculation of the loan life coverage ratio. We do
not expect to receive distributions from the project until these issues have been resolved with the project's lending group. It is anticipated that these matters will be resolved in 2003.

Interest Coverage Ratio

During 2001, we amended our articles of incorporation and our bylaws to include so-called "ring-fencing" provisions. These provisions
require the unanimous approval of our board of directors, including at least one independent director, before we can do any of the following:



49

---



The
following table sets forth the major components of one of our interest coverage ratios for the twelve months ended September 30, 2002 and the year ended December 31,
2001:

September 30,
2002

December 31,
2001(Unaudited)(in millions)Funds Flow from Operations:Operating Cash Flow(1) from Consolidated Operating Projects(2):Illinois Plants

$
333.0

$
201.3Homer City


66.6


175.2Ferrybridge and Fiddler's Ferry


10.0


(104.5
)First Hydro


36.0


45.9Other consolidated operating projects


75.5


64.1Price risk management and trading


4.0


28.2Distributions from non-consolidated Big 4 projects(3)


111.8


128.8Distributions from other non-consolidated operating projects


105.5


93.5Interest income


6.5


9.0Operating expenses


(135.8
)

(143.1
)Total funds flow from operations


613.1


498.4Interest Expense:From obligations to unrelated third parties


185.5


188.7From notes payable to Midwest Generation


114.9


116.1Total interest expense


300.4


304.8Interest Coverage Ratio


2.04


1.64


---

The
major factors affecting funds flow from operations during the twelve months ended September 30, 2002, compared to the year ended December 31, 2001, were:



50

---



Interest
expense decreased $4.4 million during the twelve months ended September 30, 2002 from the year ended December 31, 2001 as a result of a lower average debt
balance.

The
actual interest coverage ratio during 2001 and the twelve months ended September 30, 2002 was affected by the operating results of the Ferrybridge and Fiddler's Ferry projects
in the United Kingdom. The interest coverage ratio, excluding the activities of the Ferrybridge and Fiddler's Ferry projects, was 1.92 to 1 for the twelve months ended September 30, 2002.

Our
interest coverage ratio for the four quarters ended September 30, 2002 was 2.04 to 1. Accordingly, under the "ring-fencing" provisions of our articles of
incorporation and bylaws, until our interest coverage ratio exceeds 2.2 to 1 for the immediately preceding four quarters, we cannot pay a dividend without unanimous board approval. We have not paid or
declared a dividend to Mission Energy Holding Company during the first three quarters of 2002.

The
above interest coverage ratio is not determined in accordance with generally accepted accounting principles as reflected in our 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 our Consolidated Statement of Cash Flows. This
ratio does not measure the liquidity or ability of our 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 Leverage Ratio

We and our principal bank lenders measure the leverage of Edison Mission Energy using a recourse debt to recourse capital ratio as described below.

|Financial Ratio                         |  | Covenant                    |  | Actual at
September 30, 2002 |  | Description                                                                                                                                                                            
|--------------------------------------- |  | --------------------------- |  | ---------------------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Recourse Debt to Recourse Capital Ratio |  | Less than or equal to 67.5% |  | 60.5%                        |  | Ratio of (a) senior recourse debt to (b) sum of (i) shareholder's equity per our balance sheet adjusted by comprehensive income after December 31, 1999, plus (ii) senior recourse debt

51

---

Discussion of Recourse Debt to Recourse Capital Ratio

The recourse debt to recourse capital ratio of Edison Mission Energy at September 30, 2002 and December 31, 2001 was calculated as follows:

September 30,
2002

December 31,
2001(Unaudited)(in millions)Recourse Debt(1)Corporate Credit Facilities

$
78.1

$
203.6Senior Notes


1,600.0


1,700.0Guarantee of termination value of Powerton/Joliet operating leases


1,423.1


1,431.9Coal and Capex Facility


176.9


251.6Other


27.7


46.3Total Recourse Debt to Edison Mission Energy

$
3,305.8

$
3,633.4Adjusted Shareholder's Equity(2)

$
2,157.6

$
2,039.0Recourse Capital(3)

$
5,463.4

$
5,672.4Recourse Debt to Recourse Capital Ratio


60.5
%

64.1
%


---

During
the nine months ended September 30, 2002, the recourse debt to recourse capital ratio improved due to:



During
2001, the recourse debt to recourse capital ratio was adversely affected by a decrease in our shareholder's equity from $1.1 billion of after-tax losses
attributable to the loss on sale of our Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. We sold the Ferrybridge and Fiddler's Ferry power plants in
December 2001 due, in part, to the adverse impact of the negative cash flow pertaining to these plants.

52

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Subsidiary Financing Plans

The estimated capital and construction expenditures of our subsidiaries for the fourth quarter of 2002 is $38.6 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, we have committed to provide funds for capital expenditures needed by the power plant. We expect to contribute $27.6 million in 2002 and 2003 to fund the estimated capital
expenditures of this project, of which $16.6 million was contributed during the nine-month period ended September 30, 2002. See "Note 6. Commitments and
Contingencies."

On
August 9, 2002, our subsidiary, Midwest Generation, LLC, exercised its option to purchase the Illinois peaker power units that were subject to a lease with a third-party
lessor. As disclosed in "Off-Balance Sheet Transactions" in our 2001 Annual Report on Form 10-K, this operating lease was structured to maintain a minimum amount of
equity (3% of the acquisition price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases).
In order to fund the purchase, we received $255 million as repayment of the note receivable held by us and paid $300 million plus outstanding lease obligations to the owner-lessor.
Accordingly, our net cash outlay was $45.7 million. These peaker units were recorded as assets and are being depreciated over their estimated useful lives of 15 years.

Chicago In-City Obligation

Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, our subsidiary committed to install one or more
gas-fired electric generating units having an additional gross dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago (referred to as the
In-City Obligation). The acquisition documents require that commercial operation of this project commence by December 15, 2003. Due to additional capacity for new
gas-fired generation in the Mid-America Interconnected Network, generally referred to as the MAIN Region, and the improved reliability of power generation in the Chicago area,
we are in discussions with Commonwealth Edison and the City of Chicago regarding alternatives to construction of 500 MW of capacity, which we do not believe is needed at this time. There can be no
assurance that these discussions will result in an agreement to terminate the In-City Obligation. If we were to install this additional capacity, we estimate that the cost could be as much
as $320 million.

Edison Mission Midwest Holdings

Our wholly-owned subsidiary, Edison Mission Midwest Holdings, has the following maturities of long-term debt at September 30, 2002 (in
millions):

Amount

Due Date$
911.0

December 2003808.3

December 2004$
1,719.3


Edison
Mission Midwest Holdings plans to refinance the $911 million debt obligation prior to its expiration in December 2003. Completion of this refinancing is subject to a
number of uncertainties, including the availability of credit from financial institutions in light of industry conditions. Accordingly, there is no assurance that we will be able to refinance this
debt when it becomes due or that, if we are able to complete a refinancing, that the amount and the terms will not be substantially different from those under our current credit facility.

53

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Valley Power Peaker Project

During 2001, a subsidiary of ours began construction of a 300 MW gas-fired peaker plant located adjacent to the Loy Yang B coal-fired
power plant site in Australia, which we refer to as the Valley Power Peaker project. We own a 60% interest in the Valley Power Peaker project through a subsidiary, with the remaining interest held by
our 51.2% affiliate, Contact Energy. The peaker units will service peaking demand within the National Energy Market of Eastern Australia and, specifically, within the State of Victoria by selling the
output of the peakers directly into the pool and by entering into financial contracts related to pool prices with a variety of generation and retail businesses. Construction of the peaker plant was
completed during the first half of 2002. Construction financing of this project was provided through an interim financing, which was replaced on November 4, 2002 with 108 million
Australian dollars in long-term financing.

Sunrise Project Financing

We own a 50% interest in Sunrise Power Company, which owns a natural gas-fired facility currently under construction in Kern County, California, which
we refer to as the Sunrise project. The Sunrise project consists of two phases. Phase I, a simple-cycle gas-fired facility (320 MW), was completed on June 27, 2001.
Phase II, conversion to a combined-cycle gas-fired facility (560 MW), is currently scheduled to be completed in July 2003. Sunrise Power entered into a long-term
power purchase agreement with the California Department of Water Resources on June 25, 2001. For further discussion related to this agreement, see "Part II, Item 1. Legal
ProceedingsSunrise Proceedings." The construction of the Sunrise project has been funded with equity contributions by its partners, including us. Sunrise Power has engaged a financial
advisor to assist with obtaining project financing. In order to obtain project financing, a number of uncertainties need to be resolved related to the power purchase agreement, the credit of the
Department of Water Resources and certain environmental permits. If these uncertainties are resolved, we believe that project financing can be obtained in 2003 which would result in a distribution of
approximately $126 million.

Loan Agreement in Connection with Power Sales Agreement

In connection with the restructuring of the power sales agreement with an unaffiliated electric utility, a wholly-owned subsidiary borrowed $84 million
under a note purchase agreement to finance the purchase of the power sales agreement held by a third party, make a deposit under a note purchase agreement, and pay for transaction costs. The note is
non-recourse to Edison Mission Energy. Debt service is funded and secured by payments from the power sales agreement. The interest rate under the note purchase agreement is fixed at 7.31%
and is due in June 2015. Principal payments under the note purchase agreement are $0.4 million in 2002, $0.8 million in 2003, $1.5 million in 2004, $2.2 million in
2005, $3.0 million in 2006 and $76 million due after 2006.

Intercompany Tax-Allocation Payments

We are included in the consolidated federal and state income tax returns of Edison International and we participate in a tax-allocation arrangement
with other subsidiaries of Edison International. We have historically received tax-allocation payments related to domestic net operating losses incurred by us. The amount and timing of
tax-allocation payments are dependent, in part, on the consolidated taxable income of Edison International and its subsidiaries and other factors, including specific procedures regarding
allocation of state taxes. We are not eligible to receive tax-allocation payments for tax losses until such time as Edison International and its subsidiaries generate sufficient taxable
income in order to be able to utilize our tax losses in the consolidated income tax returns for Edison International and its subsidiaries. This occurred in 2002, and, accordingly, we received
$368 million in tax-allocation payments from Edison International, which included $213 million related to the amount due December 31, 2001 and $155 million as
an estimated tax-allocation payment for 2002.

54

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MARKET RISK EXPOSURES

Our primary market risk exposures are associated with the sale of electricity from and the procurement of fuel for our uncontracted generating plants. These risks
arise from fluctuations in electricity and fuel prices, emission and transmission rights, interest rates and foreign currency exchange rates. We manage these risks in part by using derivative
financial instruments in accordance with established policies and procedures. See "Current Developments" and "Credit Ratings" for a discussion of market developments and their impact on our credit and
the credit of our counter-parties.

Commodity Price Risk

Our energy trading activities and merchant power plants expose us to commodity price risks. Commodity price risks are actively monitored to ensure compliance with
our risk management policies. Policies are in place which limit the amount of total net exposure we may enter into at any point in time. Procedures exist which allow for monitoring of all commitments
and positions with regular reviews by a risk management committee. We perform a "value at risk" analysis in our daily business to measure, monitor and control our overall market risk exposure. The use
of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the worst expected 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, we supplement this approach with
the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counter-party credit exposure limits.

Electric
power generated at our merchant plants is generally sold under bilateral arrangements with utilities and power marketers under short-term contracts with terms of two
years or less, or, in the case of the Homer City facilities, to the Pennsylvania-New Jersey-Maryland Power Pool (PJM) or the New York Independent System Operator (NYISO). As discussed
further below, beginning in 2003, we will also be selling a significant portion of the power generated from our Illinois Plants into wholesale energy markets. In order to provide more predictable
earnings and cash flow, we may hedge a portion of the electric output of our merchant plants, the output of which is not committed to be sold under long-term contracts. When appropriate,
we manage the spread between electric prices and fuel prices, and use forward contracts, swaps, futures, or options contracts to achieve those objectives.

Our
revenues and results of operations during the estimated useful lives of our 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 our merchant plants are located. Among the factors that influence the price of power in these markets
are:



55

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

Americas

Illinois Plants

Electric power generated at the Illinois Plants is currently sold under three power purchase agreements with 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 have a term of up to five years,
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.

Virtually
all of our energy and capacity sales from the Illinois Plants in the first nine months of 2002 were to Exelon Generation under the power purchase agreements, and we expect this
to continue during the remainder of 2002. Under each of the power purchase agreements, Exelon Generation, upon notice by a given date, has the option in effect to terminate each agreement with respect
to all or a portion of the units subject to it.

In
July 2002, under the power purchase agreement related to our coal-fired generation units, Exelon Generation notified us of its exercise of its option to purchase
1,265 MW of capacity and energy during 2003 (of a possible total of 3,949 MW subject to option) from the option coal units. As a result, 2,684 MW of capacity of the Will County 1 and 2, Joliet 6 and
7, and Powerton 5 and 6 units will no longer be subject to the power purchase agreement after January 1, 2003. The notification received from Exelon Generation has no effect on its commitments
to purchase capacity from these units for the balance of 2002. 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 option coal units retained for 2003. Exelon Generation remains committed to purchase the capacity of certain committed units having 1,696 MW of
capacity for both 2003 and 2004.

The
following table lists the committed coal units, the units for which Exelon Generation has exercised its call option for 2003, and the units which, as of January 1, 2003, will
be released from the

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terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

Coal-Fired Units

|                  |                    |       |     | Summer(1)
Capacity Charge
($ per MW Month) |        | Non-Summer(1)
Capacity Charge
($ per MW Month) |        | Energy Prices
($/MWhr)
|----------------- | ------------------ | ----- | --- | ------------------------------------------ | ------ | ---------------------------------------------- | ------ | ----------------------
|
|
|Committed Units   |                    |       |     |                                            |        |                                                |        |                       
|                  | Waukegan Unit 7    |       | 328 |                                            | 11,000 |                                                | 12,000 |                       
|                  | Crawford Unit 8    |       | 326 |                                            | 11,000 |                                                | 12,000 |                       
|                  | Will County Unit 4 |       | 520 |                                            | 11,000 |                                                | 12,000 |                       
|                  | Joliet Unit 8      |       | 522 |                                            | 11,000 |                                                | 12,000 |                       
|                  |                    |       |     |                                            |        |                                                |        |                       
|                  |                    | 1,696 |     |                                            |        |                                                |        |                       
|Option Units(2)   |                    |       |     |                                            |        |                                                |        |                       
|                  | Waukegan Unit 6    |       | 100 |                                            | 21,300 |                                                | 15,520 |                       
|                  | Waukegan Unit 8    |       | 361 |                                            | 21,300 |                                                | 15,520 |                       
|                  | Fisk Unit 19       |       | 326 |                                            | 21,300 |                                                | 15,520 |                       
|                  | Crawford Unit 7    |       | 216 |                                            | 21,300 |                                                | 15,520 |                       
|                  | Will County Unit 3 |       | 262 |                                            | 21,300 |                                                | 15,520 |                       
|                  |                    |       |     |                                            |        |                                                |        |                       
|                  |                    | 1,265 |     |                                            |        |                                                |        |                       
|Released Units(3) |                    |       |     |                                            |        |                                                |        |                       
|                  | Will County Unit 1 |       | 156 |                                            | (3     | )                                              | 15,520 |                       
|                  | Will County Unit 2 |       | 154 |                                            | (3     | )                                              | 15,520 |                       
|                  | Joliet Unit 6      |       | 314 |                                            | (3     | )                                              | 15,520 |                       
|                  | Joliet Unit 7      |       | 522 |                                            | (3     | )                                              | 15,520 |                       
|                  | Powerton Unit 5    |       | 769 |                                            | (3     | )                                              | 15,520 |                       
|                  | Powerton Unit 6    |       | 769 |                                            | (3     | )                                              | 15,520 |                       
|                  |                    |       |     |                                            |        |                                                |        |                       
|                  |                    | 2,684 |     |                                            |        |                                                |        |                       
|                  |                    |       |     |                                            |        |                                                |        |                       
|                  |                    | 5,645 |     |                                            |        |                                                |        |                       
|                  |                    |       |     |                                            |        |                                                |        |                       

---

In
October 2002, under the power purchase agreements related to our Collins Station and peaking units, Exelon Generation notified Midwest Generation of its exercise of its option
to terminate the existing power purchase agreements during 2003 with respect to (a) 1,614 MW of capacity and energy (of a possible total of 2,698 MW subject to the option to terminate) from the
Collins Station, a natural gas and oil-fired electric generating station, and (b) 113 MW of capacity and energy (of a possible total of 807 MW subject to the option to terminate)
from the natural gas and oil-fired peaking units, in accordance with the terms of each applicable power purchase agreement. As a result, 1,614 MW of

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capacity from the Collins Units 2, 4 and 5, and 113 MW of capacity from the Lombard 33 and Calumet 33 and 34 peaking units, will no longer be subject to a power purchase agreement after
January 1, 2003. The notification received from Exelon Generation has no effect on its commitments to purchase capacity from these generating units for the balance of 2002. 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 generating units not previously terminated for 2003 (1,084 MW from the Collins Station and 694 MW from the peaking units).

The
following table lists the generating units at the Collins Station and the peaking units as to which Exelon Generation has not exercised its option to terminate for 2003, the
generating units and peaking units which, as of January 1, 2003, will, as a result of the exercise by Exelon Generation of its option to terminate, be released from the terms of the power
purchase agreement, and the peaking units as to which Exelon Generation exercised its option to terminate effective as of January 1, 2002, along with related pricing information set forth in
the respective power purchase agreements.

Collins Station and Peaking Units

|               |                  |       |     | Summer(1)
Capacity Charge
($ per MW Month) |       | Non-Summer(1)
Capacity Charge
($ per MW Month) |       | Energy Prices
($/MWhr) |      
|-------------- | ---------------- | ----- | --- | ------------------------------------------ | ----- | ---------------------------------------------- | ----- | ---------------------- | -----
|
|
|Option Units   |                  |       |     |                                            |       |                                                |       |                        |      
|               | Collins Unit 1   |       | 554 |                                            | 8,333 |                                                | 6,666 |                        | 2,083
|               | Collins Unit 3   |       | 530 |                                            | 8,333 |                                                | 6,666 |                        | 2,083
|               |                  |       |     |                                            |       |                                                |       |                        |      
|               |                  | 1,084 |     |                                            |       |                                                |       |                        |      
|               | Peaking Units    |       | 694 |                                            | 9,500 |                                                | 7,600 |                        | 1,500
|Released Units |                  |       |     |                                            |       |                                                |       |                        |      
|               | Collins Unit 2   |       | 554 |                                            | (2    | )                                              | 6,666 |                        | (2   
|               | Collins Unit 4   |       | 530 |                                            | (2    | )                                              | 6,666 |                        | (2   
|               | Collins Unit 5   |       | 530 |                                            | (2    | )                                              | 6,666 |                        | (2   
|               |                  |       |     |                                            |       |                                                |       |                        |      
|               |                  | 1,614 |     |                                            |       |                                                |       |                        |      
|               | Peaking Units    |       | 113 |                                            | (2    | )                                              | 7,600 |                        | (2   
|               | Peaking Units(3) |       | 137 |                                            | (3    | )                                              | (3    | )                      | (3   

---

The
energy and capacity from any units which do not remain 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. Thus, we will be subject to the market risks related to the price of energy
and

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capacity described above. We expect capacity prices for merchant energy sales will, in the near term, be substantially lower than those we currently receive under our existing agreements (with the
possibility of minimal revenues due to the current oversupply conditions in this marketplace). We further expect that the lower revenues resulting from this difference will be offset in part by energy
prices, which we believe will, in the near term, be higher for merchant energy sales than those we currently receive under our existing agreements, as indicated below in the table of forward-looking
prices. We intend to manage this price risk, in part, by accessing both the direct 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 us for wholesale sales of electricity from the Illinois Plants are expected to be "direct customer" and
"over-the-counter." Direct customer transactions are bilateral sales to regional buyers that principally include investor-owned utilities, municipal utilities, rural electric
cooperatives and retail energy suppliers. Transactions in the direct customer market include real-time, daily and longer term structured sales that meet the specific requirements of
wholesale electricity consumers. Over-the-counter markets are generally accessed through third-party brokers and electronic exchanges, and include forward sales of electricity.
The most liquid over-the-counter markets in the Midwest region are "Into Cinergy," and, to a lesser extent, "Into ComEd."

"Into
Cinergy" and "Into ComEd" are bilateral markets for the sale or purchase of electrical energy for future delivery. The emergence of "Into Cinergy," and "Into ComEd" as commercial
hubs for the trading of physical power has not only facilitated transparency of wholesale power prices in the Midwest, but also aided in the development of risk management strategies that are utilized
to mitigate commodity price volatility. Energy is traded in the form of physical delivery of megawatt-hours. Delivery is either made (1) into the receiving control area's transmission system (i.e.,
Cinergy's or ComEd's transmission system) by the seller's daily election of control area interface, or (2) by procuring energy generated from a source within the receiving control area. Almost
all of the Illinois Plants have busbar delivery that meets the "Into ComEd" delivery criteria. Performance of transactions in these markets is secured by liquidated damages and, in the case of less
creditworthy counter-parties, credit support provisions such as letters of credit and cash margining arrangements.

The
following table sets forth the forward month-end market prices for energy per megawatt hour for the calendar 2003 and calendar 2004 "strips" (defined as energy purchases
for the entire calendar year) as publicly quoted for sales "Into ComEd" and "Into Cinergy" during the first nine months of 2002. As indicated above, 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*

|                   |  | 2003 |       | 2004
|------------------ |  | ---- | ----- | ----
|
|
|January 31, 2002   |  | $    | 27.26 |     
|February 28, 2002  |  |      | 28.96 |     
|March 31, 2002     |  |      | 32.50 |     
|April 30, 2002     |  |      | 32.55 |     
|May 31, 2002       |  |      | 30.85 |     
|June 30, 2002      |  |      | 29.54 |     
|July 31, 2002      |  |      | 28.64 |     
|August 31, 2002    |  |      | 28.75 |     
|September 30, 2002 |  |      | 29.16 |     

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Into Cinergy**

|                   |  | 2003 |       | 2004
|------------------ |  | ---- | ----- | ----
|
|
|January 31, 2002   |  | $    | 28.38 |     
|February 28, 2002  |  |      | 30.30 |     
|March 31, 2002     |  |      | 33.82 |     
|April 30, 2002     |  |      | 34.03 |     
|May 31, 2002       |  |      | 31.74 |     
|June 30, 2002      |  |      | 31.08 |     
|July 31, 2002      |  |      | 29.34 |     
|August 31, 2002    |  |      | 29.63 |     
|September 30, 2002 |  |      | 30.56 |     

---

The
average price that we derive from electricity sales is normally higher than a 24-hour price as we manage our generation to optimize on-peak periods when power
prices are higher.

Midwest
Generation intends to hedge a portion of its merchant portfolio risk. 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 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 Midwest Generation's liquidity and upon the
over-the-counter forward sales markets' having sufficient liquidity to enable Midwest Generation to identify counter-parties who are able and willing to enter into hedging
transactions with Midwest Generation. Due to factors beyond Midwest Generation'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. This decrease in market liquidity may require Midwest Generation to rely more heavily on
sales to end user counter-parties in the direct customer markets. See "Credit Risks."

In
addition to the prevailing market prices, the ability of Midwest Generation 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, we will suspend operations of Units 1 and 2 at our Will County plant and
Units 4 and 5 at our Collins Station at the end of 2002 until market conditions improve. If market conditions were to be depressed for an extended period of time, we would need to consider
decommissioning these units, which would result in a charge against income.

Midwest
Generation's ability to transmit energy to counter-party delivery points to consummate spot sales and hedging transactions may be affected by transmission constraints. Although
the Federal Energy Regulatory Commission (FERC) and the relevant industry participants are working to minimize

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such issues, Midwest Generation cannot determine how quickly or how effectively such issues will be resolved.

A
group of transmission-owning utilities has asked the FERC to permit them to join the Pennsylvania-New Jersey-Maryland Power Pool (PJM), and the FERC granted those requests,
with conditions, in an order issued on July 31, 2002. These companies include Commonwealth Edison and American Electric Power. As recently filed by Commonwealth Edison with FERC, Commonwealth
Edison will join PJM either as an individual transmission owner, or as a member of an Independent
Transmission Company (ITC). Furthermore, the Commonwealth Edison transmission system, to which the Illinois Plants are directly interconnected, is expected to be fully integrated into the PJM market
structure by December of 2003. National Grid is currently in discussions with American Electric Power, Commonwealth Edison and Dayton Power and Light to form an ITC that would operate under the PJM
umbrella and oversight. We believe that Commonwealth Edison's integration into the PJM market will improve our ability to sell electricity into a well developed, stable, transparent, and liquid cash
market without additional transmission charges. The expanded PJM market will be interconnected by numerous extra-high voltage transmission ties and will include (in addition to the
existing market encompassed by PJM) the service territories of Commonwealth Edison, American Electric Power, Illinois Power, Virginia Power, and Dayton Power and Light. Furthermore, as a condition of
approval of the requests to join PJM, the FERC is requiring PJM and its counterpart transmission entity in the Midwest (the Midwest ISO) to form a common, seamless energy market by
October 2004, which would further expand the areas into which we may sell power without incurring multiple transmission charges. The companies are planning to begin the first phase of the
integration process during first quarter 2003 by turning over their respective transmission service operations to PJM under the terms and conditions of the PJM Open Access Transmission Tariff. The
first phase of this integration process is intended to eliminate rate-pancaking across the current PJM region and the new PJM West region, of which both Commonwealth Edison and American Electric Power
will be a part.

Homer City Facilities

Electric power generated at the Homer City facilities is sold under bilateral arrangements with domestic utilities and power marketers under
short-term contracts with terms of two years or less, or to the PJM or the New York Independent System Operator (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.

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The
following table depicts the average historical market prices per megawatt hour in PJM during the first nine months of 2002 and 2001:

24-Hour PJM
Historical Prices*2002

2001January

$
20.52

$
36.66February


20.62


29.53March


24.27


35.05April


25.68


34.58May


21.98


28.64June


24.98


26.61July


30.01


30.21August


30.41


43.99September


29.00


22.44Nine-Month Average

$
25.27

$
31.97


---

As
shown on the above table, the average historical market prices at the Homer City busbar (delivery point) during the first nine months of 2002 are below the average market prices
during the first nine months of 2001. These forward prices will continue to fluctuate as a result of a number of factors, including natural gas prices, electricity demand which is affected by weather
and 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. At the end of October 2002, our forecasted yearly average 24-hour PJM price for 2002
was $25.64, compared to the actual yearly average 24-hour PJM price of $29.07 in 2001. Our forecasted yearly average 24-hour PJM prices are based on
year-to-date actual data and a forecast for the remainder of the year based on current market information.

The
following table sets forth the forward month-end market prices for energy per megawatt hour for the calendar 2003 and calendar 2004 "strips" (defined as energy purchases
for the entire calendar year) for sales in PJM during the first nine months of 2002.

24-Hour PJM
Forward Prices*2003

2004January 31, 2002

$
25.48

$
26.31February 28, 2002


27.11


27.59March 31, 2002


29.69


29.66April 30, 2002


29.19


28.81May 31, 2002


28.40


28.24June 30, 2002


27.96


28.09July 31, 2002


27.94


28.43August 31, 2002


28.10


28.17September 30, 2002


29.00


28.99


---

The
forward prices at PJM West (delivery point) are generally higher than the prices of the Homer City busbar (delivery point) due to transmission congestion charges. The average PJM
West price has

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been 3% higher than the average Homer City busbar price during the past 24 months. The average price that the Homer City facilities derive from electricity sales is normally higher than a
24-hour price as we manage our generation to optimize the on-peak periods when power prices are higher.

The
ability of our 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 Edison Mission Energy's Annual Report on
Form 10-K for the year ended December 31, 2001, 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 our control.

Europe and Middle East

United Kingdom

Since 1989, our plants in the U.K. have sold their electrical energy and capacity through a centralized electricity pool, which established a
half-hourly clearing price, also referred to as the pool price, for electrical energy. On March 27, 2001, this system was replaced by the U.K. government with a bilateral physical
trading system referred to as the new electricity trading arrangements. The First Hydro plant has entered into forward contracts of varying terms that expire on various dates through
August 2005.

The
new electricity trading arrangements provide for, among other things, the establishment of a range of voluntary short-term power exchanges and brokered markets operating
from a year or more in advance to 3.5 hours (effective July 2, 2002, this time period became 1 hour) before a trading period of one-half hour; a balancing mechanism to
enable the system operator to balance generation and demand and resolve any transmission constraints; 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 grid operator retains the right under the new market
mechanisms to 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 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. Physical bilateral contracts have replaced the prior financial contracts for differences, but have a similar commercial function. A key feature of the new
arrangements is to require firm physical delivery, which means that a generator must deliver, and a consumer must take delivery of, its net contracted positions or pay for any energy imbalance at
highly volatile imbalance prices calculated by the market operator. A consequence of this new system has been to increase greatly the motivation of parties to contract in advance and to further
develop forwards and futures markets of greater liquidity than at present. Furthermore, another consequence of the market change is that counter-parties may require additional credit support,
including parent company guarantees or letters of credit.

The
legislation introducing the new trading arrangements set a principal objective for the Gas and Electric Market Authority to "protect the interests of consumerswhere
appropriate by promoting competition." This represents a shift in emphasis toward the consumer interest. However, this is qualified by a recognition that license holders should be able to
finance their activities. The Utilities Act of 2000 also contains new powers for the Secretary of State to issue guidance to the Gas and Electric Market Authority on social and environmental matters,
changes to the procedures for modifying licenses and a new power for the Gas and Electric Market Authority to impose financial penalties on companies for breach of license conditions. We are
monitoring the operation of these new provisions.

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During
2001, our operating income from the First Hydro plant decreased $105.9 million from the prior year primarily due to the removal of a formal capacity mechanism in the new
trading arrangements and the oversupply of generation in the market resulting in a sharp fall in the market value for capacity. In addition, First Hydro's operating results were adversely affected in
the second half of 2001 by a fall in the differential of the peak daytime energy price compared to the cost of purchasing power at nighttime to pump water back to the top reservoir. This was a
reflection both of excess generating capacity on the United Kingdom system as a whole and also of the practice of generators holding plants on the system at part load to protect themselves against the
adverse affects of being out of balance in the new market. During 2002 there has been further downward pressure on wholesale prices and on peak/off peak differentials.

Despite
the foregoing, First Hydro's interest coverage ratio, when measured for the twelve-month period ended June 30, 2002, was above the default threshold in its bond financing
documents, and it was able to make the July 31, 2002 interest payment without recourse to the project's debt service reserve. We believe that should market and trading conditions experienced
thus far in 2002 be sustained for the balance of the year, First Hydro's interest coverage ratio will also be above the default and distribution thresholds when measured for the twelve-month period
ended December 31, 2002. Compliance by First Hydro with these and other requirements of its bond financing documents are subject, however, to market conditions for the sale of energy and
ancillary services. These market conditions are beyond our 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 2001 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 further mitigate 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.A substantial portion of Contact Energy's generation output is hedged by sales to retail electricity customers
and forward contracts with other wholesale electricity counter-parties. Contact Energy has entered into forward contracts of varying terms that expire on various dates through March 31, 2007
and option contracts of varying terms that expire on various dates through December 31, 2003. The New Zealand Government commissioned an inquiry into the electricity industry in
February 2000. Following the inquiry report the New Zealand Government released a Government Policy Statement, at the center of which was a call for the industry to rationalize the three
existing industry codes, form a single governance structure and address transmission pricing methodology. The Government Policy Statement also requested a model use of system agreement be developed,
that is, a framework by which the retailers contract for services from each of the distribution networks, and a consumer complaints ombudsman be established. An essential theme throughout the
Government Policy Statement was the desire that the industry retain a private

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multilateral self-governing structure. 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 put forward 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. The Commission conditioned this authorization upon:



The
authorization will expire four years from the date of the implementation of the rulebook, or on March 31, 2007, whichever is earlier.

Credit Risks

In conducting our price risk management and trading activities, we contract with a number of utilities, energy companies and financial institutions. Due to
factors beyond our 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 our credit risk. In addition, the decrease in market liquidity may require
us to rely more heavily on wholesale electricity sales to direct customer markets which may increase our credit risk. In the event a counter-party were to default on its trade obligation, we would be
exposed to the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing counter-party were unable to pay the resulting liquidated
damages owed to us. Further, we would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counter-party defaulted.

To
manage credit risk, we look at the risk of a potential default by our counter-parties. Credit risk is measured by the loss we would record if our counter-parties failed to perform
pursuant to the terms of their contractual obligations. We have established controls to determine and monitor the creditworthiness of counter-parties and use master netting agreements whenever
possible to mitigate our exposure to counter-party risk. We may require counter-parties to pledge collateral when deemed necessary. We try to manage the credit in the portfolio based on credit
ratings. We use published ratings of counter-parties to guide us in the process of setting credit levels, risk limits and contractual arrangements including master netting agreements. Where external
ratings are not available, we conduct internal assessments of credit risks of counter-parties using publicly disclosed information, such as financial statements, regulatory filings, and press
releases. The credit quality of our counter-parties is reviewed regularly by our risk management committee. We also monitor the concentration of credit risk from various positions, including
contractual commitments. Credit concentration is determined on both an individual and group counter-party basis. In addition to continuously monitoring our credit exposure to our counter-parties, we
also take appropriate steps to limit exposures, initiate actions to lower credit exposure and take credit reserves if appropriate.

Exelon
Generation accounted for 36% and 42% of our consolidated operating revenues in 2001 and 2000, respectively. Exelon Generation represents 39% of our consolidated operating revenues
in the first nine months of 2002. We expect the percentage to be less in 2003 because a smaller number of plants will be subject to contracts with Exelon Generation. See "Market Risk
ExposuresAmericasIllinois Plants." Any failure of Exelon Generation to make payments under the power purchase agreements could adversely affect our results of operations and
financial condition.

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Interest Rate Risk

Interest rate changes affect the cost of capital needed to finance the construction and operation of our projects. We have 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 our project financings.
Interest expense included $26.8 million and $12.1 million of additional interest expense for the nine months ended September 30, 2002 and 2001, respectively, as a result of
interest rate hedging mechanisms. We have 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.

We
had short-term obligations of $52.1 million at September 30, 2002, consisting of borrowings under a construction facility for the Valley Power Peaker project
and a floating rate loan related to Contact Energy. The fair values of these obligations approximated their carrying values at September 30, 2002, 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 our total
long-term obligations (including current portion) was $4.8 billion at September 30, 2002, compared to the carrying value of $6 billion.

Foreign Exchange Rate Risk

Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of our equity contributions to, and distributions from,
our international projects. At times, we have hedged a portion of our 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, we have used statistical
forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. We 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 Loy Yang B plant 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, we have 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 nine months of 2002, foreign currencies in the U.K., Australia and New Zealand increased in value compared to the U.S. dollar by 8.0%, 6.2% and 12.9%, respectively
(determined by the change in the exchange rates from December 31, 2001 to September 30, 2002). The increase in value of these currencies was the primary reason for the foreign currency
translation gain of $70.9 million during the first nine months of 2002.

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 September 2003. At September 30, 2002, the outstanding notional amount of the contracts totaled
$31.5 million and the fair value of the contracts totaled $(0.3) million. During the first nine months of 2002, Contact Energy recognized a foreign exchange loss of $0.4 million
related to the contracts that matured during the period.

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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.

We
will continue to monitor our 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):

September 30,
2002

December 31,
2001(Unaudited)Derivatives:Interest rate:Interest rate swap/cap agreements

$
(39.7
)
$
(35.8
)Interest rate options


(1.1
)

(1.0
)Commodity price:Forwards


38.6


63.8Futures


(0.5
)

(8.4
)Options


(0.6
)

0.4Swaps


(141.8
)

(137.6
)Foreign currency forward exchange agreements


(0.3
)

(0.6
)Cross currency interest rate swaps


14.9


27.6


In
assessing the fair value of our non-trading derivative financial instruments, we use 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 our commodity risk management assets and liabilities (as of September 30, 2002) (in
millions):

|                                                   |  | Total Fair
Value |        | Maturity
<1 year |   | Maturity
1 to 3
years |   | Maturity
4 to 5
years |      | Maturity
>5 years |  
|-------------------------------------------------- |  | ---------------- | ------ | ---------------- | - | --------------------- | - | --------------------- | ---- | ----------------- | -
|
|Prices actively quoted                             |  | $                | 7.5    |                  | $ | 5.3                   |   | $                     | 2.3  |                   | $
|Prices based on models and other valuation methods |  |                  | (111.8 | )                |   | (7.3                  | ) |                       | (7.0 | )                 |  
|                                                   |  |                  |        |                  |   |                       |   |                       |      |                   |  
|Total                                              |  | $                | (104.3 | )                | $ | (2.0                  | ) | $                     | (4.7 | )                 | $
|                                                   |  |                  |        |                  |   |                       |   |                       |      |                   |  

The
fair value of the electricity rate swap agreements (included under commodity price-swaps) entered into by the Loy Yang B 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

On September 1, 2000, we acquired the trading operations of Citizens Power LLC and, subsequently, combined them with our risk management and trading
operations, now conducted by our subsidiary, Edison Mission Marketing & Trading, Inc. As a result of a number of industry and credit related factors, we have minimized our price risk
management activities and our trading activities with

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third parties not related to our power plants or investments in energy projects. See "Current Developments." To the extent we engage in trading activities, we seek to manage price risk
and 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. Approximately 2,746 GWh of our energy trading contracts (excluding the power sales agreement with an unaffiliated electric utility) were physically settled
during the third quarter ended September 30, 2002. We generally balance forward sales and purchase contracts and manage our exposure through a value at risk analysis as described further below.

The
fair value of the financial instruments, including forwards, futures, options and swaps, related to energy trading activities as of September 30, 2002 and December 31,
2001, which include energy commodities, are set forth below (in millions):

|                  |  | September 30, 2002 |       | December 31, 2001
|----------------- |  | ------------------ | ----- | -----------------
|
|
|Forward contracts |  | $                  | 123.5 |                  
|Futures contracts |  |                    | 0.1   |                  
|Option contracts  |  |                    | 0.1   |                  
|Swap agreements   |  |                    | 5.9   |                  
|                  |  |                    |       |                  
|Total             |  | $                  | 129.6 |                  
|                  |  |                    |       |                  

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 we purchased and restructured and a long-term power supply agreement with another unaffiliated party. We 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 our energy trading assets and liabilities (as of September 30, 2002)
(in millions):

|                                                   |  | Total Fair
Value |      | Maturity
<1 year |   | Maturity
1 to 3
years |   | Maturity
4 to 5
years |      | Maturity
>5 years
|-------------------------------------------------- |  | ---------------- | ---- | ---------------- | - | --------------------- | - | --------------------- | ---- | -----------------
|
|Prices actively quoted                             |  | $                | 2.5  |                  | $ | 5.4                   |   | $                     | (2.9 | )                
|Prices based on models and other valuation methods |  |                  | 93.4 |                  |   | (3.4                  | ) |                       | 3.3  |                  
|                                                   |  |                  |      |                  |   |                       |   |                       |      |                  
|Total                                              |  | $                | 95.9 |                  | $ | 2.0                   |   | $                     | 0.4  |                  
|                                                   |  |                  |      |                  |   |                       |   |                       |      |                  

The
net realized and unrealized gains or losses arising from energy trading activities for the three and nine month periods ended September 30, 2002 and 2001 are as follows (in
millions):

|                   |  | Three Months Ended
September 30, |      | Nine Months Ended
September 30, |  
|------------------ |  | -------------------------------- | ---- | ------------------------------- | -
|
|
|Operating Revenues |  |                                  |      |                                 |  
|Forward contracts  |  | $                                | 19.8 |                                 | $
|Futures contracts  |  |                                  | (0.1 | )                               |  
|Option contracts   |  |                                  | (0.5 | )                               |  
|Swap agreements    |  |                                  | (5.6 | )                               |  
|                   |  |                                  |      |                                 |  
|Total              |  | $                                | 13.6 |                                 | $
|                   |  |                                  |      |                                 |  

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The
unrealized gain (loss) from energy trading activities included in the above amounts was $2 million and $6.3 million for the three month periods ended
September 30, 2002 and 2001, respectively, and
$13.3 million and $(10.6) million for the nine month periods ended September 30, 2002 and 2001, respectively.

Off-Balance Sheet Transactions

For a discussion of Edison Mission Energy's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" on page 70 of
Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

Purchase of Equipment Under Lease

On August 9, 2002, our subsidiary, Midwest Generation, LLC, exercised its option to purchase the Illinois peaker power units that were subject to a
lease with a third-party lessor. As disclosed in "Off-Balance Sheet Transactions" in our 2001 Annual Report on Form 10-K, this operating lease was structured to maintain
a minimum amount of equity (3% of the acquisition price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as
synthetic leases). In order to fund the purchase, we received $255 million as repayment of the note receivable held by us and paid $300 million plus outstanding lease obligations to the
owner-lessor. Accordingly, our net cash outlay was $45.7 million. These peaker units were recorded as assets and are being depreciated over their estimated useful lives of 15 years.

Environmental Matters and Regulations

For a discussion of Edison Mission Energy's environmental matters, refer to "Environmental Matters and Regulations" on page 74 of Edison Mission Energy's
Annual Report on Form 10-K for the fiscal year ended December 31, 2001 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 as of December 31, 2001, except as follows.

We
anticipate that upgrades to our environmental controls to reduce nitrogen oxide (NOx) emissions will result in capital expenditures of $14 million for the fourth quarter of
2002 and $18.2 million in 2003. The capital program at the Illinois Plants has been reduced by $310 million for the period 2003-2005 due to the suspension of work related to
two Powerton Station SCRs. This decision to reduce capital expenditures was made in light of current market conditions. See "Market Risk Exposures." We believe that given the amount of
environmental control technology already installed, the remaining planned installations (excluding the Powerton SCRs), and the market forecast price of NOx credits, we will be able to comply with all
NOx emission requirements in a cost-effective manner.

Beginning
with the 2003 ozone season (May 1 through September 30), we must comply with an average NOx emission rate of 0.25 lb NOx/mmBtu of heat input. This limitation is
commonly referred to as the East St. Louis State Implementation Plan (SIP). This regulation is a State of Illinois requirement. Compliance with this standard will be met by averaging the emissions of
all our power plants. Additional burner controls planned for installation at Powerton in the spring of 2003 along with over-compliance at our other Illinois plants, will facilitate
compliance with this standard.

Beginning
with the 2004 ozone season, an additional NOx emission regulation will go into effect. This federally mandated regulation, commonly referred to as the "NOx SIP Call" will cap
NOx emissions within a 19-state region east of the Mississippi with a tonnage cap on NOx emissions. This program allows NOx trading similar to the current SO2 trading program already in
effect. Our compliance plan is to rely upon a combination of strategies. We have already qualified for early reduction credits by reducing NOx emissions at various plants ahead of the imposed
deadline.

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Additionally, the installation of emission control technology at select plants will ensure over-compliance at those individual plants with pending NOx emission limitations. Finally, NOx
emission trading will be utilized as needed to comply with any shortfall in emission credits anticipated with the deferral of the SCR projects at our Powerton Station.

Enforcement Issues.We own an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns
and operates a liquefied natural gas import terminal and cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to
EcoEléctrica a notice of violation and a compliance order alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of
EcoEléctrica met with the Environmental Protection Agency at that time to discuss the notice of violation and compliance order. On August 15, 2002, the U.S. Department of Justice
notified EcoEléctrica that it was preparing to bring a federal court action for violations of the Clean Air Act and regulations promulgated thereunder, and requested a meeting with
EcoEléctrica to discuss and possibly settle the matter. EcoEléctrica has informed the Department of Justice of its willingness to participate in such a meeting. We expect
that the initial meeting with the Department of Justice will take place in December 2002.

Critical Accounting Policies

For a discussion of Edison Mission Energy's critical accounting policies, refer to "Critical Accounting Policies" on page 80 of Edison Mission Energy's
Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

New Accounting Standards

Statement of Financial Accounting Standard No. 133

In December 2001, the Derivative Implementation Group of the Financial Accounting Standards Board issued a revised interpretation of "Normal Purchases and
Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity," referred to as Statement No. 133 Implementation Issue Number C15. Under this revised
interpretation, our forward electricity contracts no longer qualify for the normal sales exception since we have net settlement agreements with our counter-parties. In lieu of following this exception
in which we record revenue on an accrual basis, we believe our forward sales agreements qualify as cash flow hedges. Under a cash flow hedge, we record the fair value of the forward sales agreements
on our balance sheet and record the effective portion of the cash flow hedge as part of other comprehensive income. The ineffective portion of our cash flow hedges is recorded directly in our income
statement. We implemented this interpretation on April 1, 2002. We recorded assets at fair value of $11.9 million, deferred taxes of $5.5 million and a $6.4 million
increase to other comprehensive income as the cumulative effect of adoption of this interpretation.

EITF Issue No. 02-03 Related to Energy Contracts

In October 2002, the FASB Emerging Issues Task Force (commonly referred to as EITF) reached a consensus to rescind EITF No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management Activities," subject to transition positions, as part of its deliberations on Issue No. 02-03, "Recognition
and Reporting of Gains and Losses on Energy Trading Contracts," under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities,"
and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." The rescission of EITF No. 98-10 means that
energy trading and risk management activities will no longer be marked to market as trading activities, but will instead follow Statement of Financial Accounting Standards No. 133, "Accounting
for Derivatives" (SFAS No. 133). Under SFAS No. 133, each energy contract must be assessed to determine whether or not it meets the definition of a derivative subject to SFAS
No. 133. If an energy contract meets the definition of a derivative, then it

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would be recorded at fair value (i.e., mark-to-market), subject to permitted exceptions. If an energy contract does not meet the definition of a derivative, then it would be
recorded on an accrual basis. As a result of this new consensus, we will discontinue application of EITF No. 98-10 for our energy trading operations for all new contracts entered
into after October 25, 2002 and will instead apply SFAS No. 133 to these transactions. Under the transition rules, we will record a cumulative change in accounting as of
January 1, 2003 for any energy contracts entered into prior to October 25, 2002 that no longer qualify for mark-to-market accounting. We are conducting a review
of our existing contracts to determine the impact of this change in accounting for contracts outstanding at October 25, 2002.

Statement of Financial Accounting Standard No. 142

Effective January 1, 2002, we 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. The statement
requires that goodwill should be tested for impairment using a two-step approach. The first step used to identify a potential impairment compares the fair value of a reporting unit to its
carrying amount, including goodwill. If the fair value of the reporting unit is less than its carrying amount, the second step of the impairment test is performed to measure the amount of the
impairment loss. The second step of the impairment test is a comparison of the implied fair value of goodwill to its carrying amount. The impairment loss is equal to the excess carrying amount of the
goodwill over the implied fair value. We completed the first step described above for each of the components of our goodwill. The fair value of the reporting units for the Contact Energy and First
Hydro operations was in excess of related book value at January 1, 2002. Accordingly, no impairment of the goodwill related to these reporting units was recorded upon adoption of this standard.
We concluded that fair value of the reporting unit related to the Citizens Power LLC acquisition was less than our book value and, accordingly, the goodwill related to this reporting unit was
impaired at January 1, 2002.

During
the third quarter of 2002, we completed the second step of the impairment test described above. Such analysis resulted in a goodwill impairment of $14 million, net of
$8.8 million of income tax benefit, associated with the Citizens Power LLC acquisition. Estimates of fair value were determined using comparable transactions. In accordance with SFAS
No. 142, this decrease to continuing operations was recorded as of January 1, 2002 as a cumulative effect of a change in accounting principle, reflected in our consolidated income
statement for the nine months ended September 30, 2002.

Included
in "Restricted cash and other assets" on our consolidated balance sheet are customer contracts with a gross carrying amount of $23.9 million and accumulated amortization
of $1.1 million at September 30, 2002. The contracts have a weighted average amortization period of 20 years. For the three and nine months ended September 30, 2002, the
amortization expense was $0.3 million and $1.1 million, respectively. Based on the current amount of intangible assets subject to amortization, the estimated amortization expense for
fiscal years 2003 through 2007 is $1.4 million each year.

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Changes
in the carrying amount of goodwill, by segment, for the nine months ended September 30, 2002 are as follows:

|                                                  |  | Americas |       | Asia Pacific |   | Europe and
Middle East |   | Total |      
|------------------------------------------------- |  | -------- | ----- | ------------ | - | ---------------------- | - | ----- | -----
|
|Carrying amount at December 31, 2001              |  | $        | 24.8  |              | $ | 359.5                  |   | $     | 247.4
|Impairment losses                                 |  |          | (22.8 | )            |   |                       |   |       |     
|Intangibles reclassed to other assets             |  |          |      |              |   | (24.8                  | ) |       |     
|Translation adjustments and other                 |  |          |      |              |   | 54.3                   |   |       | 19.7 
|                                                  |  |          |       |              |   |                        |   |       |      
|Carrying amount at September 30, 2002 (Unaudited) |  | $        | 2.0   |              | $ | 389.0                  |   | $     | 267.1
|                                                  |  |          |       |              |   |                        |   |       |      

The
following table sets forth what net income would have been exclusive of goodwill amortization for the three and nine months ended September 30, 2002 and September 30,
2001.

|                                            |  | Three Months Ended
September 30, |       | Nine Months Ended
September 30, |  
|------------------------------------------- |  | -------------------------------- | ----- | ------------------------------- | -
|
|
|Reported net income (loss)                  |  | $                                | 162.8 |                                 | $
|Add back: Goodwill amortization, net of tax |  |                                  |      |                                 |  
|                                            |  |                                  |       |                                 |  
|Adjusted net income (loss)                  |  | $                                | 162.8 |                                 | $
|                                            |  |                                  |       |                                 |  

Statement of Financial Accounting Standard No. 143

In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations," which will be effective on January 1, 2003. The statement 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. We are studying the effects of the new standard.

Statement of Financial Accounting Standard No. 145

In April 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses from extinguishment of debt and
accounting for leases, among other things. The portion of the statement relating to the rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment
of Debt" requires that any gain or loss on extinguishment of debt that was classified as an extraordinary item that does not meet the unusual in nature and infrequent of occurrence criteria in APB
Opinion No. 30, "Reporting the Results of OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions" shall be reclassified. The standard, effective on January 1, 2003, will require us, when adopted, to reclassify as part of Income from Continuing Operations, an extraordinary gain
of $5.7 million, net of tax, recorded in December 2001. The extraordinary gain was attributable to the extinguishment of debt that was assumed by the third-party lessors in the
December 2001 Homer City sale-leaseback transaction.

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Statement of Financial Accounting Standard No. 146

In June 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities," which will be effective on January 1, 2003. The statement 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. We do not expect this standard to have a material impact on our consolidated
financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 59 of Edison Mission Energy's Annual Report on
Form 10-K for the fiscal year ended December 31, 2001. 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), Edison Mission Energy must
maintain disclosure controls and procedures. The term "disclosure controls and procedures" is defined in the SEC's regulations to mean, as applied to Edison Mission Energy, controls and other
procedures that are designed to ensure that information required to be disclosed by Edison Mission Energy in reports filed with the SEC are 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 Edison Mission Energy in its SEC reports is accumulated and communicated to Edison Mission Energy'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 Edison Mission Energy to carry out evaluations, under the
supervision and with the participation of Edison Mission Energy's management, including its Chief Executive Officer and its Chief Financial Officer, of the effectiveness of the design and operation of
Edison Mission Energy'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.

The
Chief Executive Officer and the Chief Financial Officer of Edison Mission Energy have evaluated the effectiveness of the design and operation of Edison Mission Energy's disclosure
controls and procedures as of November 11, 2002. 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 Edison Mission Energy in its reports filed with the SEC was (1) accumulated and communicated to Edison Mission Energy'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 Edison Mission Energy also have concluded that there were no significant changes in Edison Mission Energy'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 1. LEGAL PROCEEDINGS

Sunrise Proceedings

Sunrise Power Company, in which our wholly-owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources under a
power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints
with the Federal Energy Regulatory Commission against all sellers of long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California
Public Utilities Commission complaint alleged that the contracts are "unjust and unreasonable" on price and other terms, and requests that the contracts be abrogated. The California Electricity
Oversight Board complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the alternative, abrogated
as of a future date, to allow for the possibility of renegotiation. After hearings and intermediate rulings, on July 23, 2002, the Federal Energy Regulatory Commission dismissed with prejudice
the California Public Utilities Commission and California Electricity Oversight Board complaints against Sunrise. Notwithstanding the fact that the July 23 order was, in part, a denial of
rehearing sought previously, the California Public Utilities Commission and the Energy Oversight Board then filed a request for rehearing of the July 23 order. In a notice issued on
September 20, 2002, the Federal Energy Regulatory Commission stated that it did not intend to act on such request. It is possible that the California Public Utilities Commission and the Energy
Oversight Board may try to appeal within 60 days after the September 20, 2002 notice to the federal courts of appeal.

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 a copy of the complaint.

On
May 15, 2002, Sunrise 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. The
lawsuit alleges that the defendants, including Sunrise, 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.

PMNC Litigation (Brooklyn Navy Yard)

In February 1997, a civil action was commenced in the Superior Court of the State of California, Orange County, entitled The Parsons Corporation and PMNC
v. Brooklyn Navy Yard Cogeneration

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Partners, L.P., Mission Energy New York, Inc. and B-41 Associates, L.P., Case No. 774980, in which the plaintiffs asserted general monetary claims under the
construction turnkey agreement for the project in the amount of $136.8 million. Brooklyn Navy Yard has also filed an action entitled Brooklyn Navy Yard Cogeneration Partners, L.P. v.
PMNC, Parsons Main of New York, Inc., Nab Construction Corporation, L.K. Comstock & Co., Inc. and The Parsons Corporation, in the Supreme Court of the State of New York, Kings
County, Index No. 5966/97 asserting general monetary claims in excess of $13 million under the construction turnkey agreement. On March 26, 1998, the Superior Court in the
California action granted PMNC's motion for attachment in the amount of $43 million against Brooklyn Navy Yard and attached a Brooklyn Navy Yard bank account in the amount of
$0.5 million. Brooklyn Navy Yard unsuccessfully appealed the attachment order. On the same day, the court stayed all proceedings in the California action pending the New York action. PMNC's
motion to dismiss the New York action was denied by the New York Supreme Court and further denied on appeal in September 1998. On March 9, 1999, Brooklyn Navy Yard filed a motion for
partial summary judgment in the New York action. The motion was denied and Brooklyn Navy Yard has appealed. The appeal and the commencement of discovery were suspended until June 2000 to allow
for voluntary mediation between the parties. The mediation ended unsuccessfully on March 23, 2000. On November 13, 2000, a New York appellate court issued a ruling granting summary
judgment in favor of Brooklyn Navy Yard, striking PMNC's cause of action for quantum meruit, and limiting PMNC to its claims under the construction contract. On February 14, 2002, PMNC moved to
amend the complaint in the New York action to add us as a defendant and to seek a $43 million attachment against us. This motion was heard on May 10, 2002, and the court issued an order
denying the motion on June 21, 2002. Trial was originally scheduled for October 21, 2002, and has now been rescheduled for January 2, 2003. The parties filed motions for
summary judgment in October 2002, but no hearings have been scheduled. We agreed to indemnify Brooklyn Navy Yard and our partner in the venture from all claims and costs arising from or in
connection with this litigation.

EcoEléctrica Potential Environmental Proceeding

We own an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns and operates a liquefied natural gas import terminal
and cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoEléctrica a notice of violation and a compliance order
alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of EcoEléctrica met with the Environmental Protection Agency at
that time to discuss the notice of violation and compliance order. On August 15, 2002, the U.S. Department of Justice notified EcoEléctrica that it was preparing to bring a
federal court action for violations of the Clean Air Act and regulations promulgated thereunder, and requested a meeting with EcoEléctrica to discuss and possibly settle the matter.
EcoEléctrica has informed the Department of Justice of its willingness to participate in such a meeting. We expect that the initial meeting with the Department of Justice will take
place in December 2002.

Paiton Labor Suit

In April 2001, Paiton Energy was sued in the Central Jakarta District Court by the PLN Labor Union. PT PLN, the Indonesian Minister of Mines and Energy and
the former President Director of PT PLN are also named as defendants in the suit. The union sought to set aside the power purchase agreement between Paiton Energy and PT PLN and the interim agreement
then in effect between Paiton Energy and its lenders, as well as damages and other relief. On April 16, 2002, the Central Jakarta District Court dismissed the lawsuit against Paiton Energy and
the other defendants on the basis that the PLN Labor Union was not authorized under the law to bring such an action.

On
April 23, 2002, the PLN Labor Union filed a notice that it would appeal this decision. There has been no action on such appeal because the trial court has yet to relinquish
jurisdiction of the matter to the appeals court. Paiton Energy intends to contest the appeal when same is formally filed.

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BHP Fuel Supply Agreement Arbitration

PT Batu Hitam Perkasa (BHP), one of the other shareholders in Paiton Energy, has reinstated the pending arbitration to resolve disputes under the fuel supply
agreement between BHP and Paiton
Energy. The arbitration had been stayed since 1999 to allow the parties to engage in settlement discussions to restructure the coal supply chain for the Paiton project. These discussions did not
result in a settlement of all potential claims with respect to the restructuring of the coal supply chain, and BHP recently requested that the arbitration tribunal permit BHP to amend or supplement
its statement of claims to assert additional claims against Paiton Energy for breach and termination of the fuel supply agreement. BHP's total claim, to date, is $250 million.

Paiton
Energy has entered into settlement negotiations with BHP. A settlement offer has been made, and BHP has indicated that it may be willing to accept that offer, subject to the
execution of acceptable documentation and the timing of payment. Such settlement is subject to Paiton Energy obtaining approval of its lenders.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)  Exhibits

Exhibit No.

Description10.92.1

Amendment One to Credit Agreement, dated as of November 14, 2001, by and among Edison Mission Energy, Certain Commercial Lending Institutions and Citicorp USA, Inc., as Administrative Agent.10.92.2

Amendment Two to Credit Agreement, dated as of September 17, 2002, by and among Edison Mission Energy, Certain Commercial Lending Institutions and Citicorp USA, Inc., as Administrative Agent.10.104

Separation Agreement by and between William J. Heller and Edison Mission Energy effective July 31, 2002.10.105

Consulting Agreement with William J. Heller, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended September 30, 2002. (File No. 1-9936).10.106

Tax-Allocation Agreement, dated July 2, 2001, by and between Mission Energy Holding Company and Edison Mission Energy.10.107

Administrative Agreement Re Tax-Allocation Payments, dated July 2, 2001, among Edison International and subsidiary parties.99.1

Homer City Facilities Funds Flow From Operations for the twelve months ended September 30, 2002.99.2

Illinois Plants Funds Flow From Operations for the twelve months ended September 30, 2002.99.3

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


(b)  Reports on Form 8-K

The registrant filed the following report on Form 8-K during the quarter ended September 30, 2002.

Date of Report

Date Filed

Item(s) ReportedJuly 2, 2002

July 2, 2002

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 McDaniel, certify that:





|Date: November 11, 2002 |  | By: |  | /s/ Thomas R. McDanielThomas R. McDaniel President and Chief Executive Officer
|----------------------- |  | --- |  | ------------------------------------------------------------------------------

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CERTIFICATION

I,
Kevin M. Smith, certify that:





|Date: November 11, 2002 |  | By: |  | /s/ Kevin M. SmithKevin M. Smith Senior Vice President, Chief Financial
Officer and Treasurer
|----------------------- |  | --- |  | ---------------------------------------------------------------------------------------------

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