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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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Form 10-Q

|(Mark one)                                       
|-------------------------------------------------
|ý                                                
|For the Quarterly Period Ended September 30, 2003
|or                                               
|o                                                
|                                                 

Commission file number 000-24890

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

|Delaware(State or other jurisdiction of incorporation
or organization)             |  | 95-4031807(I.R.S. Employer Identification No.)
|---------------------------------------------------------------------------------- |  | ----------------------------------------------
|18101 Von Karman Avenue
Irvine, California(Address of principal executive offices) |  | 92612(Zip Code)                               

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

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Indicate
by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. YES ý    NO o

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

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

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TABLE OF CONTENTS

|        |  |                                                                                       |  | Page
|------- |  | ------------------------------------------------------------------------------------- |  | ----
|        |  | PART IFinancial Information                                                          |  |     
|Item 1. |  | Financial Statements                                                                  |  | 1   
|Item 2. |  | Management's Discussion and Analysis of Financial Condition and Results of Operations |  | 23  
|Item 3. |  | Quantitative and Qualitative Disclosures about Market Risk                            |  | 72  
|Item 4. |  | Controls and Procedures                                                               |  | 72  
|        |  | PART IIOther Information                                                             |  |     
|Item 6. |  | Exhibits and Reports on Form 8-K                                                      |  | 73  
|        |  | Signatures                                                                            |  | 74  

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PART IFINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

|                                  |                                                                                         | Three Months Ended
September 30, |         | Nine Months Ended
September 30, |          
|--------------------------------- | --------------------------------------------------------------------------------------- | -------------------------------- | ------- | ------------------------------- | ---------
|
|Operating Revenues                |                                                                                         |                                  |         |                                 |          
|                                  | Electric revenues                                                                       |                                  | $       | 991,356                         |          
|                                  | Net gains from price risk management and energy trading                                 |                                  |         | 11,232                          |          
|                                  | Operation and maintenance services                                                      |                                  |         | 11,071                          |          
|                                  |                                                                                         |                                  |         |                                 |          
|                                  |                                                                                         | Total operating revenues         |         |                                 | 1,013,659
|                                  |                                                                                         |                                  |         |                                 |          
|Operating Expenses                |                                                                                         |                                  |         |                                 |          
|                                  | Fuel                                                                                    |                                  |         | 317,190                         |          
|                                  | Plant operations and transmission costs                                                 |                                  |         | 224,238                         |          
|                                  | Plant operating leases                                                                  |                                  |         | 51,199                          |          
|                                  | Operation and maintenance services                                                      |                                  |         | 7,433                           |          
|                                  | Depreciation and amortization                                                           |                                  |         | 68,969                          |          
|                                  | Asset impairment and other charges                                                      |                                  |         |                                |          
|                                  | Administrative and general                                                              |                                  |         | 41,360                          |          
|                                  |                                                                                         |                                  |         |                                 |          
|                                  |                                                                                         | Total operating expenses         |         |                                 | 710,389  
|                                  |                                                                                         |                                  |         |                                 |          
|                                  | Operating income                                                                        |                                  |         | 303,270                         |          
|                                  |                                                                                         |                                  |         |                                 |          
|Other Income (Expense)            |                                                                                         |                                  |         |                                 |          
|                                  | Equity in income from unconsolidated affiliates                                         |                                  |         | 156,994                         |          
|                                  | Interest and other income (expense)                                                     |                                  |         | 1,712                           |          
|                                  | Interest expense                                                                        |                                  |         | (129,582                        | )        
|                                  | Dividends on preferred securities (Note 14)                                             |                                  |         |                                |          
|                                  |                                                                                         |                                  |         |                                 |          
|                                  |                                                                                         | Total other income (expense)     |         |                                 | 29,124   
|                                  |                                                                                         |                                  |         |                                 |          
|                                  | Income from continuing operations before income taxes and minority interest             |                                  |         | 332,394                         |          
|                                  | Provision for income taxes                                                              |                                  |         | 114,619                         |          
|                                  | Minority interest                                                                       |                                  |         | (17,347                         | )        
|                                  |                                                                                         |                                  |         |                                 |          
|Income From Continuing Operations |                                                                                         |                                  | 200,428 |                                 |          
|                                  | Income (loss) from operations of discontinued foreign subsidiaries, net of tax (Note 7) |                                  |         | (245                            | )        
|                                  |                                                                                         |                                  |         |                                 |          
|Income Before Accounting Change   |                                                                                         |                                  | 200,183 |                                 |          
|                                  | Cumulative effect of change in accounting, net of tax (Notes 4 and 14)                  |                                  |         |                                |          
|                                  |                                                                                         |                                  |         |                                 |          
|Net Income                        |                                                                                         | $                                | 200,183 |                                 | $        
|                                  |                                                                                         |                                  |         |                                 |          

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        (In thousands, Unaudited)

|                                                  |                                           | Three Months Ended
September 30,                                                                                                                                                                   |                                                                                                                                                                                                                                               | Nine Months Ended
September 30, |      
|------------------------------------------------- | ----------------------------------------- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------- | -----
|
|Net Income                                        |                                           | $                                                                                                                                                                                                  | 200,183                                                                                                                                                                                                                                       |                                 | $    
|Other comprehensive income (expense), net of tax: |                                           |                                                                                                                                                                                                    |                                                                                                                                                                                                                                               |                                 |      
|                                                  | Foreign currency translation adjustments: |                                                                                                                                                                                                    |                                                                                                                                                                                                                                               |                                 |      
|                                                  |                                           | Foreign currency translation adjustments, net of income tax expense of $260 and $20 for the three months and $1,564 and $2,131 for the nine months ended September 30, 2003 and 2002, respectively |                                                                                                                                                                                                                                               |                                 | 6,107
|                                                  |                                           | Minimum pension liability adjustment                                                                                                                                                               |                                                                                                                                                                                                                                               |                                 | (61  
|                                                  |                                           | Unrealized gains (losses) on derivatives qualified as cash flow hedges:                                                                                                                            |                                                                                                                                                                                                                                               |                                 |      
|                                                  |                                           |                                                                                                                                                                                                    | Cumulative effect of change in accounting for derivatives, net of income tax expense of $5,562 for the nine months ended September 30, 2002                                                                                                   |                                 |      
|                                                  |                                           |                                                                                                                                                                                                    | Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $21,498 and $(16,087) for the three months and $24,431 and $(1,158) for the nine months ended September 30, 2003 and
2002, respectively |                                 |      
|                                                  |                                           |                                                                                                                                                                                                    | Reclassification adjustments included in net income (loss), net of income tax benefit of $1,963 and $1,048 for the three months and $5,447 and $87 for the nine months ended September 30, 2003 and 2002,
respectively                        |                                 |      
|                                                  |                                           |                                                                                                                                                                                                    |                                                                                                                                                                                                                                               |                                 |      
|Other comprehensive income (expense)              |                                           |                                                                                                                                                                                                    | 58,957                                                                                                                                                                                                                                        |                                 |      
|                                                  |                                           |                                                                                                                                                                                                    |                                                                                                                                                                                                                                               |                                 |      
|Comprehensive Income                              |                                           | $                                                                                                                                                                                                  | 259,140                                                                                                                                                                                                                                       |                                 | $    
|                                                  |                                           |                                                                                                                                                                                                    |                                                                                                                                                                                                                                               |                                 |      

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, Unaudited)

|                                         |                                                                                                  | September 30,
2003                |            | December 31,
2002
|---------------------------------------- | ------------------------------------------------------------------------------------------------ | --------------------------------- | ---------- | -----------------
|Assets                                   |                                                                                                  |                                   |            |                  
|Current Assets                           |                                                                                                  |                                   |            |                  
|                                         | Cash and cash equivalents                                                                        |                                   | $          | 815,538          
|                                         | Accounts receivabletrade, net of allowance of $5,667 and $13,113 in 2003 and 2002, respectively |                                   |            | 371,564          
|                                         | Accounts receivableaffiliates                                                                   |                                   |            | 31,651           
|                                         | Assets under price risk management and energy trading                                            |                                   |            | 90,114           
|                                         | Inventory                                                                                        |                                   |            | 160,822          
|                                         | Prepaid expenses and other                                                                       |                                   |            | 120,004          
|                                         |                                                                                                  |                                   |            |                  
|                                         |                                                                                                  | Total current assets              |            |                  
|                                         |                                                                                                  |                                   |            |                  
|Investments in Unconsolidated Affiliates |                                                                                                  |                                   | 1,683,868  |                  
|                                         |                                                                                                  |                                   |            |                  
|Property, Plant and Equipment            |                                                                                                  |                                   | 8,174,872  |                  
|                                         | Less accumulated depreciation and amortization                                                   |                                   |            | 1,130,638        
|                                         |                                                                                                  |                                   |            |                  
|                                         |                                                                                                  | Net property, plant and equipment |            |                  
|                                         |                                                                                                  |                                   |            |                  
|Other Assets                             |                                                                                                  |                                   |            |                  
|                                         | Goodwill                                                                                         |                                   |            | 787,380          
|                                         | Deferred financing costs                                                                         |                                   |            | 48,380           
|                                         | Long-term assets under price risk management and energy trading                                  |                                   |            | 118,673          
|                                         | Restricted cash                                                                                  |                                   |            | 239,513          
|                                         | Rent payments in excess of levelized rent expense under plant operating leases                   |                                   |            | 213,726          
|                                         | Other long-term assets                                                                           |                                   |            | 150,415          
|                                         |                                                                                                  |                                   |            |                  
|                                         |                                                                                                  | Total other assets                |            |                  
|                                         |                                                                                                  |                                   |            |                  
|Assets of Discontinued Operations        |                                                                                                  |                                   | 2,566      |                  
|                                         |                                                                                                  |                                   |            |                  
|Total Assets                             |                                                                                                  | $                                 | 11,878,448 |                  
|                                         |                                                                                                  |                                   |            |                  

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, Unaudited)

|                                                     |                                                                                                                    | September 30,
2003                         |            | December 31,
2002 |          
|---------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------ | ------------------------------------------ | ---------- | ----------------- | ---------
|Liabilities and Shareholder's Equity                 |                                                                                                                    |                                            |            |                   |          
|Current Liabilities                                  |                                                                                                                    |                                            |            |                   |          
|                                                     | Accounts payableaffiliates                                                                                        |                                            | $          |                  |          
|                                                     | Accounts payable and accrued liabilities                                                                           |                                            |            | 446,712           |          
|                                                     | Liabilities under price risk management and energy trading                                                         |                                            |            | 124,354           |          
|                                                     | Interest payable                                                                                                   |                                            |            | 96,031            |          
|                                                     | Short-term obligations                                                                                             |                                            |            |                  |          
|                                                     | Current maturities of long-term obligations                                                                        |                                            |            | 1,241,843         |          
|                                                     |                                                                                                                    |                                            |            |                   |          
|                                                     |                                                                                                                    | Total current liabilities                  |            |                   | 1,908,940
|                                                     |                                                                                                                    |                                            |            |                   |          
|Long-Term Obligations Net of Current Maturities      |                                                                                                                    |                                            | 5,131,793  |                   |          
|                                                     |                                                                                                                    |                                            |            |                   |          
|Long-Term Deferred Liabilities                       |                                                                                                                    |                                            |            |                   |          
|                                                     | Deferred taxes and tax credits                                                                                     |                                            |            | 1,335,580         |          
|                                                     | Deferred revenue                                                                                                   |                                            |            | 531,088           |          
|                                                     | Long-term incentive compensation                                                                                   |                                            |            | 29,270            |          
|                                                     | Long-term liabilities under price risk management and energy trading                                               |                                            |            | 112,415           |          
|                                                     | Company-obligated mandatorily redeemable security of partnership holding solely parent debentures (Notes 8 and 14) |                                            |            | 150,000           |          
|                                                     | Preferred securities subject to mandatory redemption (Notes 8 and 14)                                              |                                            |            | 147,550           |          
|                                                     | Other                                                                                                              |                                            |            | 201,941           |          
|                                                     |                                                                                                                    |                                            |            |                   |          
|                                                     |                                                                                                                    | Total long-term deferred liabilities       |            |                   | 2,507,844
|                                                     |                                                                                                                    |                                            |            |                   |          
|Liabilities of Discontinued Operations               |                                                                                                                    |                                            | 1,753      |                   |          
|                                                     |                                                                                                                    |                                            |            |                   |          
|Total Liabilities                                    |                                                                                                                    |                                            | 9,550,330  |                   |          
|                                                     |                                                                                                                    |                                            |            |                   |          
|Minority Interest                                    |                                                                                                                    |                                            | 478,720    |                   |          
|                                                     |                                                                                                                    |                                            |            |                   |          
|Preferred Securities of Subsidiaries(Notes 8 and 14) |                                                                                                                    |                                            |            |                   |          
|                                                     | Company-obligated mandatorily redeemable security of partnership holding solely parent debentures                  |                                            |            |                   |          
|                                                     | Subject to mandatory redemption                                                                                    |                                            |            |                   |          
|                                                     |                                                                                                                    |                                            |            |                   |          
|                                                     |                                                                                                                    | Total preferred securities of subsidiaries |            |                   |          
|                                                     |                                                                                                                    |                                            |            |                   |          
|Commitments and Contingencies(Note 9)                |                                                                                                                    |                                            |            |                   |          
|Shareholder's Equity                                 |                                                                                                                    |                                            |            |                   |          
|                                                     | Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding               |                                            |            | 64,130            |          
|                                                     | Additional paid-in capital                                                                                         |                                            |            | 2,634,856         |          
|                                                     | Retained deficit                                                                                                   |                                            |            | (775,324          | )        
|                                                     | Accumulated other comprehensive loss                                                                               |                                            |            | (74,264           | )        
|                                                     |                                                                                                                    |                                            |            |                   |          
|Total Shareholder's Equity                           |                                                                                                                    |                                            | 1,849,398  |                   |          
|                                                     |                                                                                                                    |                                            |            |                   |          
|Total Liabilities and Shareholder's Equity           |                                                                                                                    | $                                          | 11,878,448 |                   | $        
|                                                     |                                                                                                                    |                                            |            |                   |          

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, Unaudited)

|                                                                        |                                                                               | 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 unconsolidated affiliates               |         
|                                                                        |                                                                               | Distributions from unconsolidated affiliates                  |         
|                                                                        |                                                                               | Depreciation and amortization                                 |         
|                                                                        |                                                                               | Deferred taxes and tax credits                                |         
|                                                                        |                                                                               | Asset impairment charges                                      |         
|                                                                        |                                                                               | Cumulative effect of change in accounting, net of tax         |         
|                                                                        | Changes in operating assets and liabilities:                                  |                                                               |         
|                                                                        |                                                                               | Decrease (increase) in accounts receivable                    |         
|                                                                        |                                                                               | Decrease in inventory                                         |         
|                                                                        |                                                                               | Decrease (increase) in prepaid expenses and other             |         
|                                                                        |                                                                               | Increase in rent payments in excess of levelized rent expense |         
|                                                                        |                                                                               | Increase in accounts payable and accrued liabilities          |         
|                                                                        |                                                                               | Increase (decrease) in interest payable                       |         
|                                                                        |                                                                               | Increase (decrease) in long-term incentive compensation       |         
|                                                                        |                                                                               | Decrease (increase) in net assets under risk management       |         
|                                                                        | Other operating, net                                                          |                                                               |         
|                                                                        |                                                                               |                                                               |         
|                                                                        |                                                                               |                                                               | 489,634 
|                                                                        | Operating cash flows 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 and lease swap agreements, net                           |                                                               |         
|                                                                        | Cash dividends to minority shareholders                                       |                                                               |         
|                                                                        | Financing costs                                                               |                                                               |         
|                                                                        |                                                                               |                                                               |         
|                                                                        |                                                                               |                                                               | 84,532  
|                                                                        | Financing cash flows 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 assets                                                  |                                                               |         
|                                                                        | Decrease in restricted cash                                                   |                                                               |         
|                                                                        | Investments in other assets                                                   |                                                               |         
|                                                                        |                                                                               |                                                               |         
|                                                                        |                                                                               |                                                               | (416,774
|                                                                        | Investing cash flows from discontinued operations                             |                                                               |         
|                                                                        |                                                                               |                                                               |         
|                                                                        |                                                                               | Net cash used in investing activities                         |         
|                                                                        |                                                                               |                                                               |         
|Effect of exchange rate changes on cash                                 |                                                                               |                                                               | 7,033   
|                                                                        |                                                                               |                                                               |         
|Net increase in cash and cash equivalents                               |                                                                               |                                                               | 168,428 
|Cash and cash equivalents at beginning of period                        |                                                                               |                                                               | 647,240 
|                                                                        |                                                                               |                                                               |         
|Cash and cash equivalents at end of period                              |                                                                               |                                                               | 815,668 
|Cash and cash equivalents classified as part of discontinued operations |                                                                               |                                                               | (130    
|                                                                        |                                                                               |                                                               |         
|Cash and cash equivalents of continuing operations                      |                                                                               | $                                                             | 815,538 
|                                                                        |                                                                               |                                                               |         

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, 2003        (Dollars in millions, Unaudited)

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, 2003 are not necessarily indicative of the operating
results for the full year.

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

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

Current Developments

A number of significant developments during late 2001 and 2002 adversely affected independent power producers and subsidiaries of major integrated energy
companies that sell a sizable portion of their generation into the wholesale energy market (sometimes referred to as merchant generators), including several of EME's subsidiaries. These developments
included lower prices and greater volatility in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of most major market participants,
decreased availability of debt financing or refinancing, and a resulting decline of liquidity in the energy markets due to growing concern about the ability of counterparties to perform their
obligations. Since the beginning of 2003, several merchant generators have reached agreements to extend existing bank credit facilities and at least three merchant generators have filed for Chapter 11
protection under the United States Bankruptcy Code.

On
October 28, 2003, Standard & Poor's Ratings Service downgraded EME's senior unsecured credit rating to B from BB-. Standard & Poor's also lowered the
credit ratings of EME's wholly owned indirect subsidiaries, Edison Mission Midwest Holdings (syndicated loan facility to B from BB-) and Edison Mission Marketing & Trading
(corporate credit rating to B from BB-). Standard & Poor's placed the ratings of all these entities on CreditWatch with negative implications. These ratings actions did not trigger
any defaults under EME's credit facilities or those of the other affected entities.

As
a result of the October 28, 2003 Standard & Poor's downgrade of Edison Mission Midwest Holdings to B from BB-, the cash on deposit in the cash flow recapture
account ($246 million) related to Edison Mission Midwest Holdings' indebtedness was required to be used to prepay that indebtedness, with the amount of such prepayment applied ratably to the
$911 million and $808 million tranches thereof. Therefore, on October 29, 2003, $130 million from the cash flow recapture account was applied to the $911 million
tranche, and $116 million to the $808 million tranche, thereby reducing Edison Mission Midwest Holdings' debt obligations to $781 million and $692 million, respectively. In
the future, so long as Edison Mission Midwest Holdings' ratings remain at the current level or lower, amounts of excess cash flow deposited in the cash flow recapture account at the end of each
calendar quarter will be used upon deposit to prepay, pro rata, amounts then outstanding under these bank

6

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facilities.
The Edison Mission Midwest Holdings $781 million of debt maturing on December 11, 2003 will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings does
not have sufficient cash to repay this indebtedness when due.

On
November 13, 2003, EME's subsidiary, Mission Energy Holdings International, Inc. received a commitment letter from Citigroup, Credit Suisse First Boston,
JPMorganChaseBank and Lehman Brothers Inc. to provide a three-year, $700 million secured loan intended to provide bridge financing to asset sales, including the sale of some or all
of its international operations, depending upon, among other things, market prices. Subject to completion, the net proceeds from this financing will be used to make an equity contribution of
approximately $550 million in Edison Mission
Midwest Holdings which, together with cash on hand, will be used to repay Edison Mission Midwest Holdings' $781 million indebtedness due on December 11, 2003. The remaining net proceeds
from this financing will be used to repay indebtedness of a foreign subsidiary under the Coal and CapEx facility guaranteed by EME. Mission Energy Holdings International owns substantially all of
EME's international operations, through its subsidiary, MEC International B.V. The commitment letter provides that collateral for this financing includes a pledge of:



In
addition to the pledges of collateral, the commitment letter provides for guarantees of the loan by a number of EME domestic subsidiaries, including a guarantee by Edison Mission
Finance Co., which will pledge its receivable from EME Homer City Generation L.P. under a revolving loan agreement (under which $499 million was outstanding at September 30, 2003) as
security for such guarantee. The commitment letter also provides for:



The
commitment letter provides that Mission Energy Holdings International will covenant to prepay the indebtedness in an amount equal to the net after tax proceeds from any international
asset sales when such proceeds exceed $50 million, from certain issuances of indebtedness and equity, and from specified domestic asset sales when such proceeds exceed $200 million. In
certain circumstances, prepayment of indebtedness will be required in an amount equal to 100% of net after tax proceeds from the sale of certain of the domestic subsidiary guarantors of such
indebtedness.

In
addition, the commitment letter provides for maintenance of a minimum twelve month interest coverage ratio beginning March 2004. Funding of this loan is subject to completion
of definitive documentation and a number of closing conditions, including obtaining certain consents and required corporate authorizations by EME and Mission Energy Holding Company. Completion of this
loan is subject to uncertainty and, accordingly, there is no assurance that definitive documentation will be completed and the closing conditions will be fulfilled.

7

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A
failure to repay, extend or refinance the Edison Mission Midwest Holdings $781 million obligation is likely to result in a default under the Mission Energy Holding Company
senior secured notes and term loan. These events could make it necessary for Mission Energy Holding Company or EME, or both, to file a petition for reorganization under Chapter 11 of the United
States Bankruptcy Code. EME's independent accountants' audit opinion for the year ended December 31, 2002 contains an explanatory paragraph that indicates the consolidated financial statements
have been prepared on the basis that EME will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises
substantial doubt about EME's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this
uncertainty.

Note 2. Acquisitions and Dispositions

Acquisitions

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

Dispositions

In October 2003, EME agreed to sell its 40% interest in a development project in Thailand to a third party. Completion of the sale, currently expected
during the fourth quarter of 2003, is subject to closing conditions, including obtaining regulatory approval. Net proceeds from the sale are expected to be approximately $13 million payable in
two installments, one in December 2003 and the other in June 2004.

In
July 2003, Gordonsville Energy Limited Partnership, in which EME owns a 50% interest, agreed to sell the Gordonsville cogeneration facility to Virginia Electric and Power
Company. Completion of the sale, currently expected during the fourth quarter of 2003, is subject to closing conditions. Net proceeds from the sale, including distribution of a debt service reserve
fund, are expected to be approximately $32 million. EME recorded an impairment charge of $6 million during the second quarter of 2003 related to the planned disposition of this
investment.

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

Note 3. Asset Impairment and Other Charges

During the second quarter of 2003, EME recorded an asset impairment charge of $245 million ($150 million, after tax) related to eight small peaking
plants owned by its indirect subsidiary, Midwest Generation, LLC (Midwest Generation), in Illinois. The impairment charge resulted from a revised long-term outlook for capacity revenues
from the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and the current generation overcapacity in
the MAIN region market. The book value of these assets was written down from $286 million to an estimated fair market value of $41 million. The estimated fair market value was determined
based on discounting estimated future pretax cash flows using a 17.5% discount rate.

8

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During
the third quarter of 2002, EME recorded asset impairment and other charges of $86 million, consisting of $61 million relating to the write-off of
capitalized costs associated with the termination of equipment purchase contracts with Siemens Westinghouse and $25 million related to the write-off of capitalized costs associated
with the suspension of the Powerton Station SCR major capital improvement project at the Illinois Plants.

Note 4. Goodwill and Intangible Assets

Effective January 1, 2002, EME adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS
No. 142 establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. EME commenced its
annual evaluation of goodwill on October 1, 2003.

During
the third quarter of 2002, EME concluded that fair value of the goodwill related to the Citizens Power LLC acquisition was impaired by $14 million, net of $9 million
of income tax benefit and, accordingly, reported this amount as a cumulative change in accounting. In accordance with SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements,"
EME's financial statements for the first quarter of 2002 were restated to reflect the accounting change as of January 1, 2002.

Included
in "Other long-term assets" on EME's consolidated balance sheet are customer contracts with a gross carrying amount of $93 million and accumulated
amortization of $10 million at September 30, 2003. The contracts have a weighted average amortization period of 20 years. For the three and nine months ended September 30,
2003, the amortization expense was $1 million and $4 million, respectively. Based on the current amount of intangible assets subject to amortization, the estimated amortization expense
for fiscal years 2004 through 2008 is approximately $5 million each year. Intangible assets classified in "Other long-term assets" of $1 million at September 30, 2003
consist of an additional minimum pension liability at EME's subsidiary, Midwest Generation.

Changes
in the carrying amount of goodwill, by geographical segment, for the nine months ended September 30, 2003 are as follows:

|                                          |  | Americas |   | Asia Pacific |   | Europe |  | Total
|----------------------------------------- |  | -------- | - | ------------ | - | ------ |  | -----
|Carrying amount at December 31, 2002      |  | $        | 2 |              | $ | 384    |  | $    
|Goodwill resulting from an acquisition(1) |  |          |  |              |   | 43     |  |      
|Translation adjustments and other         |  |          |  |              |   | 75     |  |      
|                                          |  |          |   |              |   |        |  |      
|Carrying amount at September 30, 2003     |  | $        | 2 |              | $ | 502    |  | $    
|                                          |  |          |   |              |   |        |  |      

---

Note 5. Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory at September 30, 2003 and December 31, 2002 consisted of the
following:

September 30,
2003

December 31,
2002Coal and fuel oil

$
92

$
111Spare parts, materials and supplies


69


65Total

$
161

$
176


9

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Note 6. Accumulated Other Comprehensive Income (Loss)

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

|                              |  | Currency
Translation
Adjustments |    | Unrealized Gains
(Losses) on Cash
Flow Hedges |   | Minimum
Pension Liability
Adjustment |   | Accumulated Other
Comprehensive
Income (Loss) |    
|----------------------------- |  | -------------------------------- | -- | --------------------------------------------- | - | ------------------------------------ | - | --------------------------------------------- | ---
|Balance at December 31, 2002  |  | $                                | (8 | )                                             | $ | (193                                 | ) | $                                             | (11
|Current period change         |  |                                  | 69 |                                               |   | 69                                   |   |                                               |   
|                              |  |                                  |    |                                               |   |                                      |   |                                               |    
|Balance at September 30, 2003 |  | $                                | 61 |                                               | $ | (124                                 | ) | $                                             | (11
|                              |  |                                  |    |                                               |   |                                      |   |                                               |    

The
amount of commodity hedges included in unrealized gains (losses) on cash flow hedges, net of tax, at September 30, 2003, was a loss of $111 million. The amount of
interest rate hedges included in unrealized gains (losses) on cash flow hedges, net of tax, at September 30, 2003, was a loss of $13 million.

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

As
EME's hedged positions are realized, approximately $21 million, after tax, of the net unrealized gains on cash flow hedges at September 30, 2003 are expected to be
reclassified into earnings during the next 12 months. Management expects that when the hedged items are recognized in earnings, the net unrealized gains associated with them will be offset. The
maximum period over which EME has designated a cash flow hedge, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is
13 years. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.

Under
SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective
portion, is immediately recognized in earnings. EME recorded net gains (losses) of approximately $3 million and $(2) million during the third quarters of 2003 and 2002, respectively, and net
gains (losses) of approximately $5 million and $(2) million for the nine-month periods of 2003 and 2002, respectively, representing the amount of cash flow hedges' ineffectiveness,
reflected in net gains (losses) from price risk management and energy trading in EME's consolidated income statement.

Note 7. Discontinued Operations

Lakeland Project

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

On
December 19, 2002, the lenders to the Lakeland project accelerated the debt owing under the bank agreement that governs the project's indebtedness, and on December 20,
2002, the Lakeland project lenders appointed an administrative receiver over the assets of Lakeland Power Ltd. An administrative receiver was appointed to take control of the affairs of
Lakeland Power Ltd. and was

10

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given
a wide range of powers (specified in the U.K. Insolvency Act), including authorizing the sale of the power plant. On May 14, 2003, a third party completed the purchase of the Lakeland
power plant from the administrative receiver for £24 million. The proceeds from the sale and existing cash were used to fund partial repayment of the outstanding debt owed to
secured creditors of the project.

Due
to the appointment of the administrative receiver, EME no longer consolidates the activities of Lakeland Power Ltd. The consolidated financial statements have been restated to
conform to discontinued operations treatment for all historical periods presented. Lakeland Power Ltd.'s administrative receiver has filed a claim against Norweb Energi Ltd. for
termination of the power purchase agreement. To the extent that Lakeland Power Ltd. receives payment under its claim, such amounts will first be used to repay amounts due to creditors with any
residual amount distributed to EME's subsidiary that owns the outstanding shares of Lakeland Power Ltd. There is no assurance that there will be any cash available to distribute from the
ultimate resolution of this claim.

Ferrybridge and Fiddler's Ferry Plants

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

Summarized
results of discontinued operations are as follows:

|                                                                   |  | Three Months Ended
September 30, |    | Nine Months Ended
September 30,
|------------------------------------------------------------------ |  | -------------------------------- | -- | -------------------------------
|
|Total operating revenues                                           |  | $                                |   |                                
|Income (loss) before income taxes                                  |  |                                  | (1 | )                              
|Income (loss) from operations of discontinued foreign subsidiaries |  | $                                |   |                                

The
balance sheet at September 30, 2003 and December 31, 2002, is comprised of current assets of $2 million and $4 million, respectively, other
long-term assets of $1 million and $6 million, respectively, and current liabilities of $2 million and $3 million, respectively.

11

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Note 8. Preferred Securities

Company-Obligated Mandatorily Redeemable Securities of Partnership Holding Solely Parent Debentures

In November 1994, EME issued, through a limited partnership of which EME is the sole general partner, 3.5 million shares of 9.875% Cumulative
Monthly Income Preferred Securities, Series A at a price of $25 per security and invested the proceeds in 9.875% junior subordinated deferrable interest debentures due 2024, which were issued
by EME in November 1994. The Series A securities are redeemable at the option of the partnership, in whole or in part, with mandatory redemption in 2024 at a redemption price of $25 per
security plus accrued and unpaid distributions. In August 1995, EME also issued, through a limited partnership, 2.5 million shares of 8.5% Cumulative Monthly Income Preferred Securities,
Series B at a price of $25 per security and invested the proceeds in 8.5% junior subordinated deferrable interest debentures due 2025, which were issued by EME in August 1995. The
Series B securities are redeemable at the option of the partnership, in whole or in part, with mandatory redemption in 2025 at a redemption price of $25 per security plus accrued and unpaid
distributions. EME issued a guarantee in favor of its preferred securities holders, which guarantees the payments of distributions declared on the preferred securities, payments upon liquidation of
the limited partnership and payments on redemption with respect to any preferred securities called for redemption by the limited partnership. No securities have been redeemed as of
September 30, 2003. These securities are more fully described on page 153 of EME's annual report on Form 10-K for the year ended December 31, 2002.

Other Preferred Securities Subject to Mandatory Redemption

During 2001, a subsidiary of EME issued $104 million of Redeemable Preferred Shares (250 million shares at a price of one New Zealand dollar per
share with a dividend rate of 6.03%). The shares are redeemable in July 2006 at issuance price. At September 30, 2003, total accumulated dividends were approximately $2 million.
Optional early redemption may occur if the holders pass an extraordinary resolution to redeem the shares if certain EME subsidiaries cease to be subsidiaries of EME or in the case of failure by an EME
subsidiary to comply with the terms of the security trust deed. The security trust deed secures a limited recourse guarantee by an EME subsidiary's payment obligations to holders of the redeemable
preferred shares. These securities are more fully described on page 154 of EME's annual report on Form 10-K for the year ended December 31, 2002.

Note 9.    Commitments and Contingencies

Commercial Commitments

The following table summarizes EME's consolidated commercial commitments as of September 30, 2003. Details regarding these commercial commitments are
discussed in the sections following the table.

|                                                   |  | Amount of Commitments Per Period in U.S.$ |    | 
|-------------------------------------------------- |  | ----------------------------------------- | -- | 
|
|
|Standby letters of credit                          |  | $                                         | 79 | 
|Capital improvements at EME's project subsidiaries |  |                                           | 8  | 
|                                                   |  |                                           |    | 
|Total Commercial Commitments                       |  | $                                         | 87 | 
|                                                   |  |                                           |    | 

Fuel Supply Contracts

Midwest Generation has entered into additional fuel purchase agreements with several third-party suppliers during the first nine months of 2003. Midwest
Generation's aggregate fuel purchase

12

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commitments
under these agreements are currently estimated to be $39 million for 2003, $199 million for 2004, $195 million for 2005, $89 million for 2006, and
$91 million for 2007.

Gas Transportation Agreements

In April 2003, the Sunrise project assumed EME's obligations under a gas transportation agreement, thereby reducing EME's contractual commitments to
transport natural gas. EME's share of the commitment to pay minimum fees under its remaining gas transportation agreement, which has a term of 15 years, is currently estimated to be
$2 million for the fourth quarter of 2003; $8 million for 2004; $8 million for 2005; $8 million for 2006; and $8 million for 2007.

Contingencies



Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources. On
May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Superior Court of the State of California, Los Angeles County, against the California Department
of Water Resources, all sellers of power under long-term energy contracts entered into in 2001, including Sunrise Power Company, and Vikram Budhraja, one of the consultants involved in the
negotiation of energy contracts on behalf of
the California Department of Water Resources. The lawsuit asks the Superior Court to void all the contracts entered into in 2001, as well as all the contracts renegotiated in 2002, as a result of a
purported conflict of interest by Mr. Budhraja. Sunrise Power Company has not yet been served with the complaint. The lawsuit has been stayed pending the outcome of the appeal in a similar
lawsuit pending in the Superior Court of the State of California, Sacramento County. (Sunrise Power Company is not a defendant in that case, but the lawsuit attacks the validity of California
Department of Water Resources' long-term contracts, including that of Sunrise Power Company, on grounds of conflict of interest.)

On
May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar,
"individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including
Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated
power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of
excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with
those lawsuits. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California, and filed a motion to stay all
proceedings pending final resolution of the jurisdictional issue. On July 9, 2003, Judge Whaley of the U.S. District Court concluded the federal court lacked jurisdiction and remanded the case
to the originating San Francisco Superior Court. Defendants, including Sunrise Power Company, have stipulated to respond to the complaint thirty days after it is assigned to a specific court of the
San Francisco Superior Court. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.



On August 4, 2002, a new Electricity Market License Regulation was implemented in Turkey. The new regulation contains, among other things, a requirement
that each generator obtain a generation

13

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license.
Historically, Doga's Implementation Contract has been its sole license. The new regulation contemplates an initial fixed license fee and a yearly license fee based on the amount of energy
generated, which will increase the project's costs of operation by an undetermined amount. In addition, the new regulation allows the possibility of insertion of provisions in a new license which may
be different from those in the Implementation Contract.

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

On
October 3, 2002, Doga (and several other power producers in Turkey acting independently) filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy
Market Regulatory Authority seeking both an injunction and permanent invalidation of certain provisions of the new regulation on the grounds of the illegality and unconstitutionality of any new
license requirement that does not take into account the vested rights of a company operating pursuant to previously agreed terms of the Implementation Contract.

On
May 12, 2003, the Danistay rejected Doga's request for injunctive relief (as well as those of the other power companies with similar claims). On July 10, 2003, Doga
appealed the Danistay's ruling. Doga's appeal was heard by the General Council of the Administrative Chambers of Danistay on October 10, 2003 and was rejected. There are no further rights of
appeal against the decision regarding the injunction. The Danistay will continue to hear the merits of Doga's lawsuit. A decision is expected to be rendered late in 2004.



A subsidiary of EME, Edison Mission Marketing and Trading (referred to as EMMT) and NRG Power Marketing, Inc. (referred to as NRG Power Marketing) are
parties to a contract pursuant to which NRG Power Marketing sells 217,000 MWhr of electricity annually to EMMT. EMMT then resells this electricity to an unconsolidated 25%-owned affiliate, CL Power
Sales Eight, L.L.C. (referred to as CL Eight). On May 14, 2003, NRG Power Marketing filed for protection under Chapter 11 of the United States Bankruptcy Code. On August 7, 2003, NRG
Power Marketing was successful in having the contract with EMMT rejected by the Bankruptcy Court in the Southern District of New York. EMMT had sought an order lifting the automatic stay so that EMMT
could bring a proceeding at the FERC to seek an order directing NRG Power Marketing to continue performing under the contract with EMMT; the Bankruptcy Court denied this motion. As a result, EMMT is
still obligated to provide electricity to CL Eight, but without the supply from NRG Power Marketing. EMMT is appealing both the contract rejection and the denial of its request to lift the automatic
stay to the U.S. District Court in the Southern District of New York. Briefs are being filed, but no dates for oral arguments in the appeals have been established.

EMMT
has entered into purchase agreements for a portion of the volumes due under the supply contract. Current market prices exceed the price which CL Eight is required to pay to EMMT for
the electricity delivered. To the extent EMMT suffers losses as a result of being required to resell such electricity for less than it paid to purchase it, EMMT and EME are indemnified by Peabody
Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for the acquisition of Citizens Power LLC.

14

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

Litigation

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

Guarantees and Indemnities



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



In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to environmental liabilities before and after
the date of sale as specified in the Asset Sale Agreement dated March 22, 1999. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are
subject to a requirement by Commonwealth Edison to take all reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this indemnity, a
maximum potential liability cannot be determined. The indemnification for the environmental liabilities referred to above is not limited in term and would be triggered by a valid claim from
Commonwealth Edison. Except as discussed below, EME has not recorded a liability related to this indemnity.

Midwest
Generation entered into a supplemental agreement with Commonwealth Edison on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement
obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison
50% of specific existing asbestos claims less recovery of insurance costs, and agreed to a sharing arrangement for liabilities associated with future asbestos related claims as specified in the
agreement. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement has a five-year term with an automatic renewal provision (subject to the
right to terminate). Payments are made under this indemnity by a valid claim provided from Commonwealth Edison. At September 30, 2003, Midwest Generation had $6 million recorded as a
liability related to known claims provided by Commonwealth Edison and had made $1 million in payments.

15

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In connection with the acquisition of the Homer City facilities, EME Homer City Generation L.P. (EME Homer City) agreed to indemnify the sellers with respect to
environmental liabilities before and after the date of sale as specified in the Asset Purchase Agreement dated August 1, 1998. EME guaranteed the obligations of EME Homer City. Due to the
nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration
date. Payments would be triggered under this indemnity by a claim from the sellers. EME has not recorded a liability related to this indemnity.



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



Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. EME's wholly owned subsidiary owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. A settlement agreement was
executed on January 17, 2003, and all litigation has been dismissed. EME agreed to indemnify Brooklyn Navy Yard Cogeneration Partners, L.P. for any payments due under this settlement agreement,
which are scheduled through 2006. At September 30, 2003, EME recorded a liability of $13 million related to this indemnity.



TM Star was formed for the limited purpose of selling natural gas to March Point Cogeneration Company, an affiliate through common ownership, under a fuel supply
agreement that extends through December 31, 2011. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of the obligations under the fuel supply
agreement. EME has guaranteed 50% of TM Star's obligation under the fuel supply agreement to March Point Cogeneration Company. Due to the nature of the obligation under this guarantee, a maximum
potential liability cannot be determined. TM Star has met its obligations to March Point Cogeneration Company, and, accordingly, no claims against this guarantee have been made.



EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to
repay capacity payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return
to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power contracts. In addition, subsidiaries of EME have guaranteed the obligations of Kern
River Cogeneration Company and Sycamore Cogeneration Company under their project power sales agreements to repay capacity payments to the projects' power purchaser in the event that the projects
unilaterally terminate their

16

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performance
or reduce their electric power producing capability during the term of the power contracts. The obligations under the indemnification agreements as of September 30, 2003, if payment
were required, would be $190 million. EME has no reason to believe that any of these projects will either cease operations or reduce its electric power producing capability during the term of
its power contract.



EME agreed to indemnify its lenders under its credit facilities from amounts drawn on a $43 million letter of credit issued for the benefit of the lenders
to ISAB Energy, a 49% unconsolidated affiliate, in lieu of ISAB Energy funding a debt service reserve account using additional equity contributions. Accordingly, a default under ISAB Energy's project
debt could result in a draw under the letter of credit which, in turn, would result in a borrowing under EME's credit facilities. The letter of credit is renewed each six-month period or
until ISAB Energy funds the debt service account. The indemnification is subject to the maximum amount drawn under the letter of credit. EME has not recorded a liability related to this indemnity.



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



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

Environmental Matters and Regulations

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

17

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

Note 10. Business Segments

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

|Three Months Ended                                                                 |                          | Americas |     | Asia Pacific |   | Europe |     | Corporate/
Other |     | Total
|---------------------------------------------------------------------------------- | ------------------------ | -------- | --- | ------------ | - | ------ | --- | ---------------- | --- | -----
|September 30, 2003                                                                 |                          |          |     |              |   |        |     |                  |     |      
|Operating revenues from consolidated subsidiaries                                  |                          | $        | 588 |              | $ | 292    |     | $                | 121 |      
|Net gains (losses) from price risk management and energy trading                   |                          |          | 12  |              |   | 7      |     |                  | (8  | )    
|                                                                                   |                          |          |     |              |   |        |     |                  |     |      
|                                                                                   | Total operating revenues |          | $   | 600          |   | $      | 299 |                  | $   | 113  
|                                                                                   |                          |          |     |              |   |        |     |                  |     |      
|Income (loss) from continuing operations before income taxes and minority interest |                          | $        | 355 |              | $ | 75     |     | $                | 7   |      
|                                                                                   |                          |          |     |              |   |        |     |                  |     |      
|September 30, 2002                                                                 |                          |          |     |              |   |        |     |                  |     |      
|Operating revenues from consolidated subsidiaries                                  |                          | $        | 655 |              | $ | 193    |     | $                | 102 |      
|Net gains (losses) from price risk management and energy trading                   |                          |          | 10  |              |   | (1     | )   |                  | (4  | )    
|                                                                                   |                          |          |     |              |   |        |     |                  |     |      
|                                                                                   | Total operating revenues |          | $   | 665          |   | $      | 192 |                  | $   | 98   
|                                                                                   |                          |          |     |              |   |        |     |                  |     |      
|Income (loss) from continuing operations before income taxes and minority interest |                          | $        | 309 |              | $ | 40     |     | $                | (9  | )    
|                                                                                   |                          |          |     |              |   |        |     |                  |     |      

|Nine Months Ended                                                                  |                          | Americas |       | Asia Pacific |   | Europe |     | Corporate/
Other |     | Total
|---------------------------------------------------------------------------------- | ------------------------ | -------- | ----- | ------------ | - | ------ | --- | ---------------- | --- | -----
|September 30, 2003                                                                 |                          |          |       |              |   |        |     |                  |     |      
|Operating revenues from consolidated subsidiaries                                  |                          | $        | 1,286 |              | $ | 742    |     | $                | 363 |      
|Net gains (losses) from price risk management and energy trading                   |                          |          | 39    |              |   | 2      |     |                  | (19 | )    
|                                                                                   |                          |          |       |              |   |        |     |                  |     |      
|                                                                                   | Total operating revenues |          | $     | 1,325        |   | $      | 744 |                  | $   | 344  
|                                                                                   |                          |          |       |              |   |        |     |                  |     |      
|Income (loss) from continuing operations before income taxes and minority interest |                          | $        | 199   |              | $ | 144    |     | $                | 12  |      
|                                                                                   |                          |          |       |              |   |        |     |                  |     |      
|September 30, 2002                                                                 |                          |          |       |              |   |        |     |                  |     |      
|Operating revenues from consolidated subsidiaries                                  |                          | $        | 1,278 |              | $ | 532    |     | $                | 328 |      
|Net gains (losses) from price risk management and energy trading                   |                          |          | 33    |              |   | (1     | )   |                  | (1  | )    
|                                                                                   |                          |          |       |              |   |        |     |                  |     |      
|                                                                                   | Total operating revenues |          | $     | 1,311        |   | $      | 531 |                  | $   | 327  
|                                                                                   |                          |          |       |              |   |        |     |                  |     |      
|Income (loss) from continuing operations before income taxes and minority interest |                          | $        | 359   |              | $ | 115    |     | $                | 22  |      
|                                                                                   |                          |          |       |              |   |        |     |                  |     |      

18

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Note 11. Investments

The following table presents summarized financial information of the significant subsidiary investments in unconsolidated affiliates accounted for by the equity
method. The significant subsidiary investments include the California Power Group, Watson Cogeneration Company, Four Star Oil & Gas Company, PT Paiton Energy and ISAB Energy S.r.l. The
California Power Group (not a legal entity) consists of Kern River Cogeneration Company, Sycamore Cogeneration Company, Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas
River Cogeneration Company, Sargent Canyon Cogeneration Company, and Sunrise Power Company, LLC.

Three Months Ended
September 30,

Nine Months Ended
September 30,2003

2002

2003

2002Operating revenues

$
737

$
527

$
1,908

$
1,397Operating income


342


204


709


469Net income


292


200


571


409


Note 12. Supplemental Statements of Cash Flows Information

Nine Months Ended
September 30,2003

2002Cash paidInterest (net of amount capitalized)

$
342

$
308Income taxes (receipts)

$
(51
)
$
(345
)Cash payments under plant operating leases

$
255

$
246Details of assets acquiredFair value of assets acquired

$
333

$
Liabilities assumed


58


Net cash paid for acquisitions

$
275

$



Note 13. Stock-based Compensation

Edison International has three stock-based employee compensation plans, which are described more fully in Note 15Stock Compensation Plans
included in EME's annual report on Form 10-K for the year ended December 31, 2002. EME accounts for those plans using the intrinsic value method. Upon grant, no stock-based
employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common

19

---

stock
on the date of grant. The following table illustrates the effect on net income if EME had used the fair value accounting method.

|                                                                                                                                            |  | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |  
|------------------------------------------------------------------------------------------------------------------------------------------- |  | -------------------------------- | --- | ------------------------------- | -
|
|Net income, as reported                                                                                                                     |  | $                                | 200 |                                 | $
|Add: stock-based compensation expense included in reported net income, net of related tax effects                                           |  |                                  | 1   |                                 |  
|Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects |  |                                  | (1  | )                               |  
|                                                                                                                                            |  |                                  |     |                                 |  
|Pro forma net income                                                                                                                        |  | $                                | 200 |                                 | $
|                                                                                                                                            |  |                                  |     |                                 |  

Note 14. Changes In Accounting

Adoption of New Accounting Pronouncements

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

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

Initial asset retirement obligation as of January 1, 2003

$
17Accretion expense


1Translation adjustments


2Balance of asset retirement obligation as of September 30, 2003

$
20


Had
SFAS No. 143 been applied retroactively in the nine months ended September 30, 2002, it would not have had a material effect upon EME's results of operations. The pro
forma liability for asset retirement obligation is not shown due to the immaterial impact on EME's consolidated balance sheet.

Statement of Financial Accounting Standards No. 149.In April 2003, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial
accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group
(DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into
or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in
fiscal quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The adoption of this standard had no impact on EME's consolidated financial
statements.

20

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Statement of Financial Accounting Standards No. 150.Effective July 1, 2003, EME adopted Statement of Financial
Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards for how to classify
and measure certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability or
asset, as appropriate. At July 1, 2003, EME's company-obligated mandatorily redeemable securities and redeemable preferred stock were reclassified from the mezzanine equity section to the
liability section of EME's consolidated balance sheet. Dividend payments on these instruments are being recorded as interest expense commencing July 1, 2003 on EME's consolidated statements of
income. Prior period financial statements are not permitted to be restated for either of these changes. Therefore, there was no cumulative impact due to this accounting change incurred upon adoption.
See disclosures regarding these preferred securities in Note 8Preferred Securities.

Emerging Issues Task Force No. 01-08.In May 2003, the Emerging Issues Task Force (EITF) reached a
consensus on Issue No. 01-08, "Determining Whether an Arrangement Contains a Lease," which provides guidance on how to determine whether an arrangement contains a lease that is
within the scope of SFAS No. 13, "Accounting for Leases." A lease is defined as an agreement conveying the right to use property, plant, or equipment (land and/or depreciable assets), usually
for a stated period of time. The guidance issued by the EITF could affect the classification of a power sales agreement that meets specific criteria, such as a power sales agreement for substantially
all of the output from a power plant to one customer. If a power sales agreement meets the guidance issued by the EITF, it would be accounted for as a lease subject to SFAS No. 13. The
consensus is effective prospectively for EME arrangements entered into or modified after June 30, 2003. The consensus had no impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards Interpretation No. 45.In November 2002, the FASB issued Statement
of Financial Accounting Standards Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This
interpretation establishes reporting requirements to be made by a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to
recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The adoption of this standard had no impact on EME's financial statements. See
disclosure regarding guarantees and indemnities in Note 9Commitments and Contingencies.

Accounting Pronouncements Issued But Not Yet Adopted

Other Statement of Financial Accounting Standards No. 133 Guidance.In June 2003, the Derivative Implementation
Group of the FASB under Statement No. 133 Implementation Issue Number C20 issued clarifying guidance related to pricing adjustments in contracts that qualify under the normal purchases and
normal sales exception under SFAS No. 133. This implementation guidance became effective on October 1, 2003. EME is currently re-evaluating which contracts, if any, that have
previously been designated as normal purchases or normal sales would now not qualify for this exception.

Emerging Issues Task Force No. 03-11.In July 2003, the EITF reached a consensus on Issue
No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging
Activities, and Not Held for Trading Purposes." EITF Issue No. 03-11 provides guidance on whether realized gains and losses on derivative contracts should be reported on a net or
gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and circumstances. In analyzing the facts and

21

---

circumstances,
EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal Versus Net as an Agent," should be considered. Gains and losses on non-trading derivative
instruments are recognized in net gains (losses) from price risk management and energy trading in the accompanying Consolidated Income Statements. The consensus is effective prospectively for EME
transactions or arrangements entered into or modified after September 30, 2003.

Statement of Financial Accounting Standards Interpretation No. 46.In January 2003, the FASB issued Statement
of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46). This interpretation of Accounting Research Bulletin No. 51, "Consolidated
Financial Statements," addresses consolidation by business enterprises of variable interest entities. The primary
objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such
entities are known as variable interest entities. This interpretation applies to variable interest entities created after January 31, 2003, and applies to variable interest entities in which
EME holds a variable interest that it acquired before February 1, 2003. Effective October 9, 2003, the FASB issued Statement of Financial Accounting Standards Interpretation
No. 46-6, "Effective Date of Financial Accounting Standards Interpretation No. 46, Consolidation of Variable Interest Entities." This interpretation delays the effective date
for applying the provisions of FIN 46 to variable interest entities in which EME holds a variable interest that it acquired before February 1, 2003 until the end of the first interim or annual
period ended after December 15, 2003.

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

EME
has concluded that it is the primary beneficiary of Brooklyn Navy Yard Cogeneration Partners L.P. since EME expects to absorb the majority of Brooklyn Navy Yard Cogeneration Partners
L.P.'s losses, if any, and expects to receive a majority of Brooklyn Navy Yard Cogeneration Partners L.P.'s residual returns, if any. Accordingly, EME will consolidate Brooklyn Navy Yard Cogeneration
Partners L.P. effective October 1, 2003. In accordance with the transition provisions of FIN 46, the consolidation of Brooklyn Navy Yard Cogeneration Partners L.P. will be based on the
historical cost of the assets, liabilities and non-controlling interest which would have been carried by EME effective when EME became the primary beneficiary. This means that EME will
consolidate the assets and liabilities of Brooklyn Navy Yard Cogeneration Partners L.P. using the October 1, 2003 balance sheet and eliminate intercompany balances. EME expects the
consolidation of this entity to increase total assets by approximately $364 million and total liabilities by approximately $440 million. Furthermore, EME expects to record a loss of
approximately $76 million in the fourth quarter of 2003 as a cumulative change of accounting as a result of consolidating this variable interest entity. This loss is primarily due to cumulative
losses allocated to the other 50% partner in excess of equity contributions recorded.

22

---

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

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

The Management's Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q discusses material changes in the
results of operations, financial condition and other developments of EME since December 31, 2002, and as compared to the third quarter and nine months ended September 30, 2002. This
discussion presumes that the reader has read or has access to Management's Discussion and Analysis of Results of Operations and Financial Condition included in Item 7 of EME's annual report on
Form 10-K for the year ended December 31, 2002.

General

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

As
of September 30, 2003, EME owned or leased interests in 27 domestic and 55 international operating power plants with an aggregate generating capacity of 24,079 megawatts (MW),
of which EME's share was 18,928 MW. At that date, one international power plant, totaling 355 MW of generating capacity, of which EME's anticipated share will be approximately 178 MW, was under
construction.

Current Developments

A number of significant developments during late 2001 and 2002 adversely affected independent power producers and subsidiaries of major integrated energy
companies that sell a sizable portion of their generation into the wholesale energy market (sometimes referred to as merchant generators), including several of EME's subsidiaries. These developments
included lower prices and greater volatility in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of most major market participants,
decreased availability of debt financing or refinancing, and a resulting decline of liquidity in the energy markets due to growing concern about the ability of counterparties to perform their
obligations. Since the beginning of 2003, several merchant generators have reached agreements to extend existing bank credit facilities and at least three merchant generators have filed for Chapter 11
protection under the United States Bankruptcy Code.

On
October 28, 2003, Standard & Poor's Ratings Service downgraded EME's senior unsecured credit rating to B from BB-. Standard & Poor's also lowered the
credit ratings of EME's wholly owned indirect subsidiaries, Edison Mission Midwest Holdings (syndicated loan facility to B from BB-) and Edison Mission Marketing & Trading
(corporate credit rating to B from BB-). Standard & Poor's placed the ratings of all these entities on CreditWatch with negative implications. These ratings actions did not trigger
any defaults under EME's credit facilities or those of the other affected entities.

23

---

As
a result of the October 28, 2003 Standard & Poor's downgrade of Edison Mission Midwest Holdings to B from BB-, the cash on deposit in the cash flow recapture
account ($246 million) related to Edison Mission Midwest Holdings' indebtedness was required to be used to prepay that indebtedness, with the amount of such prepayment applied ratably to the
$911 million and $808 million tranches thereof. Therefore, on October 29, 2003, $130 million from the cash flow recapture account was applied to the $911 million
tranche, and $116 million to the $808 million tranche, thereby reducing Edison Mission Midwest Holdings' debt obligations to $781 million and $692 million, respectively. In
the future, so long as Edison Mission Midwest Holdings' ratings remain at the current level or lower, amounts of excess cash flow deposited in the cash flow recapture account at the end of each
calendar quarter will be used upon deposit to prepay, pro rata, amounts then outstanding under these bank facilities. The Edison Mission Midwest Holdings $781 million of debt maturing on
December 11, 2003 will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings does not have sufficient cash to repay this indebtedness when due.

On
November 13, 2003, EME's subsidiary, Mission Energy Holdings International, Inc. received a commitment letter from Citigroup, Credit Suisse First Boston,
JPMorganChaseBank and Lehman Brothers Inc. to provide a three-year, $700 million secured loan intended to provide bridge financing to asset sales, including the sale of some or all
of its international operations depending upon, among other things, market prices. Subject to completion, the net proceeds from this financing will be used to make an equity contribution of
approximately $550 million in Edison Mission
Midwest Holdings which, together with cash on hand, will be used to repay Edison Mission Midwest Holdings' $781 million indebtedness due on December 11, 2003. The remaining net proceeds
from this financing will be used to repay indebtedness of a foreign subsidiary under the Coal and CapEx facility guaranteed by EME. Mission Energy Holdings International owns substantially all of
EME's international operations, through its subsidiary, MEC International B.V. The commitment letter provides that collateral for this financing includes a pledge of:



In
addition to the pledges of collateral, the commitment letter provides for guarantees of the loan by a number of EME domestic subsidiaries, including a guarantee by Edison Mission
Finance Co., which will pledge its receivable from EME Homer City Generation L.P. under a revolving loan agreement (under which $499 million was outstanding at September 30, 2003) as
security for such guarantee. The commitment letter also provides for:



The
commitment letter provides that Mission Energy Holdings International will covenant to prepay the indebtedness in an amount equal to the net after tax proceeds from any international
asset sales when such proceeds exceed $50 million, from certain issuances of indebtedness and equity, and

24

---

from
specified domestic asset sales when such proceeds exceed $200 million. In certain circumstances, prepayment of indebtedness will be required in an amount equal to 100% of net after tax
proceeds from the sale of certain of the domestic subsidiary guarantors of such indebtedness.

In
addition, the commitment letter provides for maintenance of a minimum twelve month interest coverage ratio beginning March 2004. Funding of this loan is subject to completion
of definitive documentation and a number of closing conditions, including obtaining certain consents and required corporate authorizations by EME and Mission Energy Holding Company. Completion of this
loan is subject to uncertainty and, accordingly, there is no assurance that definitive documentation will be completed and the closing conditions will be fulfilled.

A
failure to repay, extend or refinance the Edison Mission Midwest Holdings $781 million obligation is likely to result in a default under the Mission Energy Holding Company
senior secured notes and term loan. These events could make it necessary for Mission Energy Holding Company or EME, or both, to file a petition for reorganization under Chapter 11 of the United
States Bankruptcy Code. EME's independent accountants' audit opinion for the year ended December 31, 2002 contains an explanatory paragraph that indicates the consolidated financial statements
have been prepared on the basis that EME will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises
substantial doubt about EME's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this
uncertainty.

Acquisitions and Dispositions of Investments in Energy Plants

Acquisitions

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

Dispositions

In October 2003, EME agreed to sell its 40% interest in a development project in Thailand to a third party. Completion of the sale, currently expected
during the fourth quarter of 2003, is subject to closing conditions, including obtaining regulatory approval. Net proceeds from the sale are expected to be approximately $13 million payable in
two installments, one in December 2003 and the other in June 2004.

In
July 2003, Gordonsville Energy Limited Partnership, in which EME owns a 50% interest, agreed to sell the Gordonsville cogeneration facility to Virginia Electric and Power
Company. Completion of the sale, currently expected during the fourth quarter of 2003, is subject to closing conditions. Net proceeds from the sale, including distribution of a debt service reserve
fund, are expected to be approximately $32 million. EME recorded an impairment charge of $6 million during the second quarter of 2003 related to the planned disposition of this
investment.

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

25

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RESULTS OF OPERATIONS

CONSOLIDATED OPERATING RESULTS

Net Income Summary

Net income is comprised of the following components:

Three Months Ended
September 30,

Nine Months Ended
September 30,2003

2002

2003

2002(in millions)Income from continuing operations

$
200

$
157

$
28

$
109Income (loss) from discontinued operations





6


(2
)

21Cumulative changes in accounting








(9
)

(14
)Net Income

$
200

$
163

$
17

$
116


EME's
income from continuing operations for the third quarter and nine months ended September 30, 2003 was $200 million and $28 million, respectively, compared to
$157 million and $109 million for the third quarter and nine months ended September 30, 2002, respectively. The third quarter increase in income from continuing operations was
primarily due to $52 million in after-tax charges during 2002, higher U.S. energy prices, the start of operations at Phase 2 of the Sunrise project in June 2003, and
increased earnings from Contact Energy, the ISAB and Paiton projects. The increase in income was partially offset by lower capacity revenues from the Illinois Plants due to certain units being
released from power purchase agreements with Exelon Generation in 2003 and lower state tax benefits than in 2002. The 2002 after-tax charges consisted of a $37 million
after-tax write-off of capitalized costs related to the termination of equipment purchase contracts and a $15 million after-tax write-off of
capitalized costs related to the suspension of the SCR major capital improvements project at the Powerton Station.

The
2003 year-to-date decrease in income from continuing operations was primarily due to the asset impairment charge of $150 million described
below, reduction in revenue from EME's Illinois Plants, lower earnings from EME's First Hydro plant, and lower state tax benefits than in 2002. Partially offsetting these items were asset impairment
charges totaling $52 million, after tax, described above, higher U.S. energy prices, the start of operations at Phase 2 of the Sunrise project in June 2003, and increased earnings from
Contact Energy and the Paiton project.

The
$150 million after-tax impairment charge resulted from a revised long-term outlook for capacity revenues from eight small peaking plants in Illinois.
The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and the current generation overcapacity in the MAIN region market.
Since capacity value represents a key revenue component for these small peaking plants, the revised outlook resulted in a write-down of the book value of these assets to their estimated
fair market value.

Operating Revenues

Operating revenues increased 6% and 11% for the third quarter and nine months ended September 30, 2003, respectively, compared to the corresponding periods
of 2002. The 2003 increases were primarily due to increased electric revenues from the Homer City facilities due to increased generation and higher energy prices and increased electric revenue from
Contact Energy primarily due to higher wholesale electricity prices, higher generation, and an increase in the value of the New Zealand dollar compared to the U.S. dollar. Partially offsetting the
2003 increases was lower revenue from power purchase agreements with Exelon Generation.

26

---

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

Three Months Ended September 30,

Nine Months Ended September 30,2003

2002

2003

2002(in millions)Price risk management

$
(1
)
$
(9
)
$
(15
)
$
(7
)Energy trading


12


14


37


36Net Gains

$
11

$
5

$
22

$
29


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



Under
SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective
portion, is immediately recognized in earnings. EME recorded net gains (losses) of approximately $3 million and $(2) million during the third quarters of 2003 and 2002, respectively, and net
gains (losses) of approximately $5 million and $(2) million during the nine months ended September 30, 2003 and 2002, respectively, representing the amount of cash flow hedges'
ineffectiveness. The net gain during the third quarter and nine months ended September 30, 2003 from Homer City primarily resulted from forward contracts that expired during the period and
decreases in the difference between energy prices at PJM West Hub (where EME's subsidiary enters into forward contracts) and the energy prices at the delivery point where power generated by the Homer
City facilities is delivered into the transmission system (referred to as the Homer City busbar). The net loss related to the Illinois Plants resulted from similar differences in energy prices between
"Into ComEd" and delivery points outside "Into ComEd." These prices are used to determine the fair value of forward contracts that qualify as cash flow hedges. EME records the ineffective portion of
the change in the fair value of these contracts through the income statement. See "Market Risk ExposuresAmericas" for more information regarding forward market prices.

27

---

The
2003 net gains from energy trading activities were primarily the result of net gains from transmission congestion contracts and other power contracts in markets where EME has power
plants. The 2002 net gains from energy trading activities primarily represent gains realized on transmission congestion contracts entered into during the third quarter of 2002 and the completion of
the restructuring of a power sales agreement with an unaffiliated electric utility during the first quarter of 2002. As part of the transaction, an EME subsidiary purchased the power sales agreement
held by a third party, modified its terms and conditions, and entered into a long-term power supply agreement with another party. Although the sale and purchase of power arising from these
contracts will occur over their term, net gains of $2 million and $21 million were recorded during the third quarter and nine months ended September 30, 2002, respectively,
attributable to the fair value of the contracts (generally referred to as mark-to-market accounting).

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

Operating Expenses

Fuel costs increased 7% and 15% for the third quarter and nine months ended September 30, 2003, respectively, compared to the corresponding periods of
2002. The 2003 increases were primarily due to increased generation from the Homer City facilities and increased fuel costs from Contact Energy primarily due to higher gas prices and an increase in
the value of the New Zealand dollar compared to
the U.S. dollar. Partially offsetting the third quarter increase was lower generation from the Collins Station and coal plants in Illinois. The 2003 year-to-date
increase in Homer City generation was primarily the result of outages experienced during the first two quarters of 2002.

Plant
operations and transmission costs increased $55 million and $113 million for the third quarter and nine months ended September 30, 2003, respectively, compared
to the corresponding periods of 2002. Transmission costs were $76 million and $53 million for the third quarters of 2003 and 2002, respectively, and $193 million and
$132 million for the nine months ended September 30, 2003 and 2002, respectively. The 2003 increases in transmission costs were primarily due to higher retail sales generated by Contact
Energy and an increase in the value of the New Zealand dollar compared to the U.S. dollar.

Depreciation
and amortization expense increased $6 million and $31 million for the third quarter and nine months ended September 30, 2003, respectively, compared to
the corresponding periods of 2002. The 2003 increases were primarily due to higher depreciation expense from Contact Energy associated with the Taranaki Station acquisition. Also included in the
2003 year-to-date increase is additional depreciation expense resulting from the termination of the Midwest Generation equipment lease in August 2002.

Asset
impairment charges were $251 million for the nine months ended September 30, 2003. Asset impairment charges in 2003 consisted of $245 million related to the
impairment of eight small peaking plants owned by EME's wholly owned subsidiary, Midwest Generation, in Illinois and $6 million related to the write-down of EME's investment in the
Gordonsville project due to its planned disposition (refer to "Dispositions" for further discussion). The impairment charge relating to the peaking plants resulted from a revised
long-term outlook for capacity revenues from the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas
prices and the current generation overcapacity in the MAIN region market. See "Market Risk ExposuresIllinois Plants." The book value of these assets was written down from
$286 million to an estimated fair market value of $41 million. The estimated fair market value was determined based on discounting estimated future pretax cash flows using a 17.5%
discount rate.

28

---

Asset
impairment and other charges of $86 million for the third quarter and the nine months ended September 30, 2002 consisted of $61 million related to the
write-off of capitalized costs associated with the termination of equipment purchase contracts with Siemens Westinghouse and $25 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.

Administrative
and general expenses increased $10 million and $1 million for the third quarter and nine months ended September 30, 2003, respectively, compared to
the corresponding periods of 2002. The 2003 increases were primarily due to higher consulting fees in 2003 related to debt restructuring activities and additional long-term incentive
compensation expense related to deferred payments and annual vesting of benefits. The 2003 year-to-date increase was partially offset by charges against 2002 earnings
for severance and other related costs, which resulted from a series of actions undertaken to reduce administrative and general operating costs.

Other Income (Expense)

Equity in income from unconsolidated affiliates increased 31% and 26% for the third quarter and nine months ended September 30, 2003, respectively,
compared to the corresponding periods of 2002. The 2003 increases were primarily due to an increase in EME's share of income from the Big 4 projects, Four Star Oil & Gas and the Sunrise
project. EME's third quarter equity in income from its domestic energy projects is materially higher than equity in income related to other quarters of the year due to warmer weather during the summer
months and because a number of EME's domestic energy projects, located on the West Coast, have power sales contracts that provide for higher payments during the summer months.

Interest
and other income increased $2 million and decreased $2 million for the third quarter and nine months ended September 30, 2003, respectively, compared to the
corresponding periods of 2002. The third quarter increase was primarily due to foreign exchange gains from EME's intercompany loans. The 2003 year-to-date decrease was
primarily due to higher foreign exchange losses from EME's intercompany loans and lower interest income.

Interest
expense increased $17 million and $26 million for the third quarter and nine months ended September 30, 2003, respectively, compared to the corresponding
periods of 2002. The 2003 increases were due to higher interest costs at the Illinois Plants due to a downgrade of the credit rating of Edison Mission Midwest Holdings and higher levels of borrowings
at Contact Energy. See "Liquidity and Capital ResourcesCredit Ratings." In addition, dividend payments on EME's company-obligated mandatorily redeemable securities and
redeemable preferred stock are being recorded as interest expense commencing July 1, 2003. See "New Accounting Standards."

Income Taxes

EME's annual effective tax rate (excluding state tax reallocation benefits, the impact of a change in statutory tax rates in Turkey, and income tax benefit
related to the impairment charges) was 35% during the nine months ended September 30, 2003, compared to 46% during the first nine months of 2002. During the nine months ended
September 30, 2003 and 2002, EME recorded additional state tax benefits, net of federal income taxes, of $15 million and $26 million, respectively, as a result of participation in
a tax-allocation agreement with Edison International. The Turkish corporate tax rate decreased from 33% to 30%, retroactive to January 1, 2003, as a result of legislation passed in
April 2003. In accordance with SFAS No. 109, "Accounting for Income Taxes," the reductions in the Turkish income tax rates resulted in an increase in income tax expense of approximately
$4 million during the second quarter of 2003 due to a reduction in deferred tax assets. During the second quarter of 2003, EME recorded a tax benefit of $98 million relating to the
impairment of the small peaking plants in Illinois and its Gordonsville project.

29

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Minority Interest

Minority interest expense increased $10 million and $8 million for the third quarter and nine months ended September 30, 2003, respectively,
compared to the corresponding periods of 2002. Minority interest primarily relates to the 49% ownership of Contact Energy by the public in New Zealand.

Discontinued Operations

Lakeland Project

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

On
December 19, 2002, the lenders to the Lakeland project accelerated the debt owing under the bank agreement that governs the project's indebtedness, and on December 20,
2002, the Lakeland project lenders appointed an administrative receiver over the assets of Lakeland Power Ltd. An administrative receiver was appointed to take control of the affairs of
Lakeland Power Ltd. and was given a wide range of powers (specified in the U.K. Insolvency Act), including authorizing the sale of the power plant. On May 14, 2003, a third party
completed the purchase of the Lakeland power plant from the administrative receiver for £24 million. The proceeds from the sale and existing cash were used to fund partial repayment
of the outstanding debt owed to secured creditors of the project.

Due
to the appointment of the administrative receiver, EME no longer consolidates the activities of Lakeland Power Ltd. The consolidated financial statements have been restated to
conform to discontinued operations treatment for all historical periods presented. Lakeland Power Ltd.'s administrative receiver has filed a claim against Norweb Energi Ltd. for
termination of the power purchase agreement. To the extent that Lakeland Power Ltd. receives payment under its claim, such amounts will first be used to repay amounts due to creditors with any
residual amount distributed to EME's subsidiary that owns the outstanding shares of Lakeland Power Ltd. There is no assurance that there will be any cash available to distribute from the
ultimate resolution of this claim.

During
the third quarter and nine months ended September 30, 2003, EME recorded losses of $423 thousand and approximately $1 million, respectively, from discontinued
operations related to administrative expenses incurred as part of the close-out activities. During the third quarter of 2002 and the nine-month period ended
September 30, 2002, EME recorded income of $6 million and $18 million, respectively, from discontinued operations primarily related to operating income from the Lakeland power
plant.

Ferrybridge and Fiddler's Ferry Plants

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

During
the second quarter of 2003, EME recorded losses of $1 million from discontinued operations primarily related to taxes. During the second quarter of 2002, EME recorded
income of

30

---

$3 million
from discontinued operations primarily related to an insurance recovery from claims filed prior to the sale of the power plants.

Cumulative Effect of Change in Accounting Principle

Statement of Financial Accounting Standards No. 142

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

Statement of Financial Accounting Standards No. 143

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

REGIONAL OPERATING RESULTS

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

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

31

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Americas

|                                                                   |                                                   | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |  
|------------------------------------------------------------------ | ------------------------------------------------- | -------------------------------- | --- | ------------------------------- | -
|
|
|Operating Revenues from Consolidated Subsidiaries                  |                                                   |                                  |     |                                 |  
|                                                                   | Illinois Plants                                   |                                  | $   | 431                             |  
|                                                                   | Homer City                                        |                                  |     | 150                             |  
|                                                                   | Other                                             |                                  |     | 7                               |  
|                                                                   |                                                   |                                  |     |                                 |  
|                                                                   |                                                   | $                                | 588 |                                 | $
|                                                                   |                                                   |                                  |     |                                 |  
|Income (Loss) before Taxes and Minority Interest (Earnings/Losses) |                                                   |                                  |     |                                 |  
|                                                                   | Consolidated operations                           |                                  |     |                                 |  
|                                                                   | Illinois Plants                                   |                                  | $   | 181                             |  
|                                                                   | Homer City                                        |                                  |     | 60                              |  
|                                                                   | Charges related to cancellation of turbine orders |                                  |     |                                |  
|                                                                   | Other                                             |                                  |     | 11                              |  
|                                                                   | Unconsolidated affiliates                         |                                  |     |                                 |  
|                                                                   | Big 4 projects                                    |                                  |     | 65                              |  
|                                                                   | Four Star Oil & Gas                               |                                  |     | 13                              |  
|                                                                   | Sunrise                                           |                                  |     | 29                              |  
|                                                                   | March Point                                       |                                  |     | 2                               |  
|                                                                   | Other                                             |                                  |     | 6                               |  
|                                                                   | Regional overhead                                 |                                  |     | (12                             | )
|                                                                   |                                                   |                                  |     |                                 |  
|                                                                   |                                                   | $                                | 355 |                                 | $
|                                                                   |                                                   |                                  |     |                                 |  

Illinois Plants

|                                 |                                    | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |      
|-------------------------------- | ---------------------------------- | -------------------------------- | --- | ------------------------------- | -----
|
|StatisticsCoal-Fired Generation |                                    |                                  |     |                                 |      
|                                 | Generation (in GWhr):              |                                  |     |                                 |      
|                                 |                                    | Power purchase agreement         |     |                                 | 3,806
|                                 |                                    | Merchant                         |     |                                 | 4,195
|                                 |                                    |                                  |     |                                 |      
|                                 |                                    | Total coal-fired generation      |     |                                 | 8,001
|                                 |                                    |                                  |     |                                 |      
|                                 | Availability(1)                    |                                  |     | 95.6                            | %    
|                                 | Forced outage rate(2)              |                                  |     | 4.4                             | %    
|                                 | Average realized energy price/MWh: |                                  |     |                                 |      
|                                 |                                    | Power purchase agreement         |     | $                               | 18.06
|                                 |                                    | Merchant                         |     | $                               | 28.92
|                                 |                                    |                                  |     |                                 |      
|                                 |                                    | Total coal-fired generation      |     | $                               | 23.76
|                                 |                                    |                                  |     |                                 |      
|Capacity revenues (in millions)  |                                    | $                                | 222 |                                 | $    

---

32

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Operating
revenues from the Illinois Plants decreased $98 million and $109 million for the third quarter and nine months ended September 30, 2003, respectively,
compared to the corresponding periods of 2002. The third quarter decline was primarily due to lower capacity revenue resulting from the reduction in megawatts contracted under the power purchase
agreements with Exelon Generation as described below, partially offset by an increase in energy revenue due to the shift to merchant generation. The shift to merchant generation has resulted in
minimal capacity revenues but higher energy revenues due to higher average realized energy prices as compared to the energy prices set forth in the power purchase agreements with Exelon Generation.
The nine-month period decline was also due to lower capacity revenue resulting from the reduction in megawatts contracted
under the power purchase agreements with Exelon Generation, partially offset by an increase in energy revenue due to the shift to merchant generation.

In
accordance with the power purchase agreements, Exelon Generation released 4,548 MW of generating capacity during 2002 from the power purchase agreements at the Illinois Plants. Of the
generating capacity released by Exelon Generation, EME's subsidiary suspended operations for 1,370 MW and decommissioned 45 MW. As a result, beginning in 2003, the Illinois Plants have had 3,133 MW of
uncontracted capacity available for sale in the merchant generation market.

Exelon
Generation is obligated under the power purchase agreements to make capacity payments for the plants under contract (4,739 MW during 2003) and energy payments for electricity
produced by these plants. As a result of the decline in contracted generating capacity under the power purchase agreements, revenues from Exelon Generation as a percentage of EME's consolidated
operating revenues decreased from 55% for the third quarter of 2002 to 31% for the third quarter of 2003 and from 44% for the first nine months of 2002 to 25% for the first nine months of 2003.
Revenues from Exelon Generation were $313 million and $521 million for the third quarters of 2003 and 2002, respectively. Revenues from Exelon Generation were $606 million and
$957 million for the nine-month periods ended September 30, 2003 and 2002, respectively. For more information on the power purchase agreements, see "Market Risk
ExposuresIllinois Plants."

Earnings
from the Illinois Plants decreased $63 million and $348 million for the third quarter and nine months ended September 30, 2003, respectively, compared to
the corresponding periods of 2002. Included in the 2003 year-to-date results was an asset impairment charge of $245 million related to small peaking plants in
Illinois. Included in the 2002 results was a $25 million charge related to the write-off of capitalized costs associated with the suspension of the Powerton Station SCR major
capital improvement project. See "Consolidated Operating ResultsOperating Expenses" and "Market Risk ExposuresIllinois Plants."

In
addition to the asset impairment charge related to the small peaking plants in 2003, EME's indirect subsidiary, Midwest Generation, also reported an impairment charge of
$475 million, after tax, related to the 2,698 MW gas-fired Collins Station in its second quarter report on Form 10-Q. The impairment charge resulted from a
write-down of the book value of the Collins Station capitalized assets from $858 million to an estimated fair market value of $78 million. The impairment charge by Midwest
Generation is not reflected in the operating results of EME because the lease related to the Collins Station is treated in EME's financial statements as an operating lease and not as an asset and,
therefore, is not subject to impairment for accounting purposes. See "Liquidity and Capital ResourcesEdison Mission Energy Recourse Debt to Recourse Capital Ratio."

Earnings
from the Illinois Plants decreased $88 million, excluding the impairment charge described above, for the third quarter of 2003, compared to the corresponding period of
2002, due to lower revenues as described above, partially offset by lower fuel costs related to lower generation at the Collins Station and the coal-fired units. Earnings from the Illinois
Plants decreased $128 million, excluding the impairment charges described above, for the nine months ended September 30, 2003, compared to the corresponding period of 2002, due to lower
revenues as described above.

33

---

The
earnings of the Illinois Plants included interest income related to loans to EME of $28 million and $29 million for the third quarters of 2003 and 2002, respectively,
and $85 million and $91 million for the nine months ended September 30, 2003 and 2002, respectively. In August 2000, Midwest Generation, which owns or leases the Illinois
Plants, entered into a sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds from the sale of these facilities were loaned to EME, which also provided a guarantee of
the related lease obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded as an operating lease for accounting purposes.

Gain
(losses) from price risk management activities were $(6) million and none for the third quarter and $(2) million for both the nine months ended September 30, 2003 and 2002,
respectively. The 2003 losses primarily reflect the ineffective portion of forward contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. See
"Consolidated Operating ResultsOperating Revenues" for further discussion. Also included in the 2003 losses is a mark-to-market adjustment of an
option Midwest Generation has to purchase energy from Calumet Energy Team LLC, which is accounted for as a derivative under SFAS No. 133. The 2002 losses represent the change in market value of
futures contracts with respect to a portion of anticipated fuel purchases that did not qualify as cash flow hedges under SFAS No. 133.

Homer City

|           |                                   | Three Months Ended
September 30, |   | Nine Months Ended
September 30, |  
|---------- | --------------------------------- | -------------------------------- | - | ------------------------------- | -
|
|Statistics |                                   |                                  |   |                                 |  
|           | Generation (in GWhr)              |                                  |   | 4,042                           |  
|           | Availability(1)                   |                                  |   | 97.6                            | %
|           | Forced outage rate(2)             |                                  |   | 2.1                             | %
|           | Average realized energy price/MWh |                                  | $ | 34.57                           |  
|           | Capacity revenues (in millions)   |                                  | $ | 11                              |  

---

Operating
revenues from Homer City increased $31 million and $116 million for the third quarter and nine months ended September 30, 2003, respectively, compared to
the corresponding periods of 2002. The 2003 increases were due to increased generation and higher energy prices. The nine-month period increase in generation primarily resulted from an
unplanned outage on Unit 3 and extended outages on Units 1 and 2 during the first half of 2002. On February 10, 2002, Homer City experienced a major unplanned outage due to a collapse of the
SCR ductwork of one of the units, known as Unit 3. The unit was restored to operation on April 4, 2002 and operated with the SCR bypassed until June 19, 2003, when it was returned to
service. As a result of the Unit 3 ductwork collapse, EME 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.

Earnings
from Homer City increased $30 million and $89 million for the third quarter and nine months ended September 30, 2003, respectively, compared to the
corresponding periods of 2002. The

34

---

2003
increase in earnings is due to increased generation and higher energy prices. See "Market Risk ExposuresHomer City Facilities."

Gains
(losses) from price risk management activities were $7 million and $(1) million for the third quarter and $4 million and $(1) million for the nine months ended
September 30, 2003 and 2002, respectively. The gains (losses) primarily represent the ineffective portion of forward contracts which are derivatives that qualify as cash flow hedges under SFAS
No. 133. See "Consolidated Operating ResultsOperating Revenues" for further discussion.

Charges Related to Cancellation of Turbine Orders

In September 2002, EME notified Siemens Westinghouse of its election to terminate all of the equipment purchase contracts for nine turbines effective
October 25, 2002, in light of lower wholesale energy prices during 2002. Accordingly, EME recorded approximately $61 million to write-off capitalized costs associated with
the termination of these contracts during the third quarter of 2002.

Big 4 Projects

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

Earnings
from the Big 4 projects increased $1 million and $27 million for the third quarter and nine months ended September 30, 2003, respectively, compared to the
corresponding periods of 2002. The change in earnings was largely due to higher energy prices in 2003. The earnings from the Big 4 projects included interest expense from Edison Mission Energy Funding
of $4 million for the third quarters of 2003 and 2002. For the nine-month periods ended September 30, 2003 and 2002, earnings included interest expense from Edison Mission
Energy Funding of $12 million and $14 million, respectively.

Four Star Oil & Gas

EME owns a 37.2% direct and indirect interest, with 36.05% voting stock, in Four Star Oil & Gas Company, with majority control held by affiliates of
ChevronTexaco Corporation. Four Star Oil & Gas owns oil and gas reserves in the San Juan Basin, the Hugoton Basin, the Permian Basin, and offshore Gulf Coast and Alabama. EME's share of
earnings from Four Star Oil & Gas Company increased $10 million and $22 million for the third quarter and nine months ended September 30, 2003, respectively, compared to
the corresponding periods of 2002. The 2003 increases in earnings were primarily due to higher natural gas prices.

Sunrise

Earnings from the Sunrise project increased $17 million and $22 million for the third quarter and nine months ended September 30, 2003,
respectively, compared to the corresponding periods of 2002. The 2003 increases in earnings primarily resulted from additional earnings from the completion of Phase 2 of the Sunrise project in
June 2003.

35

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March Point

Earnings from March Point decreased $3 million for the nine months ended September 30, 2003, compared to the corresponding period of 2002. The 2003
decrease in earnings was primarily due to a planned outage in June 2003.

Other

Net earnings from other projects in the Americas region (consolidated subsidiaries and unconsolidated affiliates) decreased $8 million and
$30 million for the third quarter and nine months ended September 30, 2003, respectively, compared to the same prior year periods. The 2003 decreases were partially due to lower earnings
from the EcoEléctrica project, primarily because of lower operating revenues resulting from plant outages, and losses from the TM Star project due to a change in market value of natural
gas contracts that did not qualify for hedge accounting under SFAS No. 133. In addition, other projects included a $6 million loss for the nine-month period ended
September 30, 2003 related to the write-down of EME's investment in the Gordonsville project due to its planned disposition.

Asia Pacific

|                                                                   |                           | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |  
|------------------------------------------------------------------ | ------------------------- | -------------------------------- | --- | ------------------------------- | -
|
|
|Operating Revenues from Consolidated Subsidiaries                  |                           |                                  |     |                                 |  
|                                                                   | Contact Energy            |                                  | $   | 228                             |  
|                                                                   | Loy Yang B                |                                  |     | 47                              |  
|                                                                   | Other                     |                                  |     | 17                              |  
|                                                                   |                           |                                  |     |                                 |  
|                                                                   |                           | $                                | 292 |                                 | $
|                                                                   |                           |                                  |     |                                 |  
|Income (Loss) before Taxes and Minority Interest (Earnings/Losses) |                           |                                  |     |                                 |  
|                                                                   | Consolidated operations   |                                  |     |                                 |  
|                                                                   | Contact Energy(1)         |                                  | $   | 42                              |  
|                                                                   | Loy Yang B                |                                  |     | 14                              |  
|                                                                   | Other                     |                                  |     | 3                               |  
|                                                                   | Unconsolidated affiliates |                                  |     |                                 |  
|                                                                   | Paiton                    |                                  |     | 18                              |  
|                                                                   | Other                     |                                  |     | 1                               |  
|                                                                   | Regional overhead         |                                  |     | (3                              | )
|                                                                   |                           |                                  |     |                                 |  
|                                                                   |                           | $                                | 75  |                                 | $
|                                                                   |                           |                                  |     |                                 |  

---

36

---

Contact Energy

Operating revenues increased $89 million and $191 million for the third quarter and nine months ended September 30, 2003, respectively,
compared to the same prior year periods. The 2003 increases were due to increased retail revenues and higher generation which primarily resulted from the Taranaki Station acquisition in
March 2003. In addition, there was a 24% and 23% increase in the average exchange rate of the New Zealand dollar compared to the U.S. dollar during the third quarter and nine months ended
September 30, 2003, respectively, compared to the corresponding periods of 2002.

Earnings
from Contact Energy, included in the consolidated statements of income of EME as described above, increased $24 million and $19 million for the third quarter and
nine months ended September 30, 2003, respectively, compared to the corresponding periods of 2002. In 2003, the higher revenues discussed above were partially offset by increased operating and
interest costs associated with the Taranaki Station acquisition. In addition, 2003 earnings included a $7 million and $2 million gain for the third quarter and nine months ended
September 30, 2003, respectively, from price risk management activities related to a change in market value of electricity and financial contracts that were not designated as cash flow hedges
for hedge accounting under SFAS No. 133. No comparable amount was recorded for the first nine months of 2002.

Loy Yang B

Operating revenues increased $7 million and $10 million for the third quarter and nine months ended September 30, 2003, respectively,
compared to the corresponding periods of 2002. The 2003 increases were primarily due to a 20% and 16% increase in the average exchange rate of the Australian dollar compared to the U.S. dollar during
the third quarter and nine months ended September 30, 2003,
respectively, compared to the corresponding periods of 2002. The 2003 increases were partially offset by lower pool prices for the power sold into the wholesale energy market.

Earnings
from Loy Yang B increased $1 million for the third quarter and decreased $6 million for the nine months ended September 30, 2003, compared to the same prior
year periods. The 2003 year-to-date decrease in earnings is due to higher plant maintenance costs primarily related to the planned outage in March 2003.

Paiton Energy

Earnings from Paiton Energy increased $10 million and $15 million for the third quarter and nine months ended September 30, 2003,
respectively, compared to the corresponding periods of 2002. The 2003 increases in earnings were primarily due to lower project interest expense, lower depreciation (due to a change from 30 to
41.5 years in the useful life of the power plant resulting from an extension of the power sales agreement) and a decrease in Indonesian income taxes resulting from interest expense from partner
subordinated loans.

Other

Operating revenues from other consolidated subsidiaries in the Asia Pacific region increased $3 million and $9 million for the third quarter and
nine months ended September 30, 2003, respectively, compared to the same prior year periods. The third quarter increase is due to higher electric revenues from the Kwinana project primarily due
to an increase in the value of the Australian dollar compared to the U.S. dollar. The 2003 year-to-date increase is primarily due to higher electric revenues from the
Valley Power Peaker project in Australia. Commercial operation of the Valley Power Peaker project commenced during the second quarter of 2002.

37

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Europe(1)

|                                                                   |                           | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |  
|------------------------------------------------------------------ | ------------------------- | -------------------------------- | --- | ------------------------------- | -
|
|
|Operating Revenues from Consolidated Subsidiaries                  |                           |                                  |     |                                 |  
|                                                                   | First Hydro               |                                  | $   | 87                              |  
|                                                                   | Doga(2)                   |                                  |     | 31                              |  
|                                                                   | Other                     |                                  |     | 3                               |  
|                                                                   |                           |                                  |     |                                 |  
|                                                                   |                           | $                                | 121 |                                 | $
|                                                                   |                           |                                  |     |                                 |  
|Income (Loss) before Taxes and Minority Interest (Earnings/Losses) |                           |                                  |     |                                 |  
|                                                                   | Consolidated operations   |                                  |     |                                 |  
|                                                                   | First Hydro               |                                  | $   | (8                              | )
|                                                                   | Doga                      |                                  |     | 8                               |  
|                                                                   | Other                     |                                  |     | (1                              | )
|                                                                   | Unconsolidated affiliates |                                  |     |                                 |  
|                                                                   | ISAB                      |                                  |     | 13                              |  
|                                                                   | Other                     |                                  |     |                                |  
|                                                                   | Regional overhead         |                                  |     | (5                              | )
|                                                                   |                           |                                  |     |                                 |  
|                                                                   |                           | $                                | 7   |                                 | $
|                                                                   |                           |                                  |     |                                 |  

---

First Hydro

Operating revenues increased $13 million and $18 million for the third quarter and nine months ended September 30, 2003, respectively,
compared to the corresponding periods of 2002. The 2003 increases were primarily due to higher energy prices during the third quarter ended September 30, 2003 and a 4% and 8% increase in the
average exchange rate of the British pound compared to the U.S. dollar during the third quarter and nine months ended September 30, 2003, respectively, compared to the corresponding periods of
2002. These increases were partially offset by lower ancillary services revenues in 2003. The First Hydro plant is expected to provide for higher electric revenues during its winter months.

Losses
from First Hydro increased $3 million and $31 million for the third quarter and nine months ended September 30, 2003, respectively, compared to the same prior
year periods. The 2003 increase in losses is partially due to a $8 million and $20 million loss from price risk management activities for the third quarter and nine months ended
September 30, 2003, respectively, compared to a $4 million and $1 million loss from price risk management activities for the third quarter and nine months ended
September 30, 2002, respectively. First Hydro's gains (losses) from price risk management relate to realized losses and the change in market value of commodity contracts that are

38

---

recorded
at fair value under SFAS No. 133, with changes in fair value recorded through the income statement.

Doga

Revenues from Doga increased $5 million and $14 million for the third quarter and nine months ended September 30, 2003, respectively,
compared to the corresponding periods of 2002. The 2003 increases were primarily due to an increase in steam sales and higher natural gas prices. Earnings from Doga increased $5 million for the
third quarter of 2003, compared to the same prior year period primarily due to higher revenues described above.

ISAB

Earnings from ISAB increased $9 million and $4 million for the third quarter and nine months ended September 30, 2003, respectively, compared
to the corresponding periods of 2002. The 2003 increases were primarily due to higher generation and settlement of an insurance claim.

Other

Operating revenues from other consolidated subsidiaries in the Europe region increased $1 million and $3 million for the third quarter and nine
months ended September 30, 2003, respectively, compared to the same prior year periods. Earnings from other projects in the Europe region (consolidated subsidiaries and unconsolidated
affiliates) increased $4 million and $13 million for the third quarter and nine months ended September 30, 2003, respectively, compared to the corresponding periods of 2002. The
2003 increase in both operating revenues and earnings is primarily due to increased operating revenues from EME's Spanish Hydro project largely due to higher generation caused by more rainfall in the
first nine months of 2003, compared to the first nine months of 2002.

Regional G&A

Europe's Regional G&A decreased $1 million and $4 million for the third quarter and nine months ended September 30, 2003, respectively,
compared to the same prior year periods. The 2003 decrease in Regional G&A is primarily due to lower development costs.

39

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LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2003, EME and its subsidiaries had cash and cash equivalents of $816 million and EME had available a total of $107 million
of borrowing capacity under its $212 million corporate credit facility. EME's consolidated debt at September 30, 2003 was $6.4 billion, including debt maturing on
December 11, 2003 which is owed by EME's largest subsidiary, Edison Mission Midwest Holdings. In addition, EME's subsidiaries have approximately $7 billion of long-term lease
obligations that are due over periods ranging up to 32 years.

On
September 15, 2003, Sunrise Power Company, LLC completed a non-recourse project financing of $345 million. EME received a distribution of approximately
$151 million from the proceeds of this financing. As a result of the successful completion of the Sunrise project financing, EME repaid the $275 million component of EME's corporate
credit facility and retired Tranche A upon its expiration on September 16, 2003. Tranche B expires on September 17, 2004.

Financing Plan for $781 Million Debt Maturity

On November 13, 2003, EME's subsidiary, Mission Energy Holdings International, Inc. received a commitment letter from Citigroup, Credit Suisse First
Boston, JPMorganChaseBank and Lehman Brothers Inc. to provide a three-year, $700 million secured loan intended to provide bridge financing to asset sales, including the sale of some
or all of its international operations, depending upon, among other things, market prices. Subject to completion, the net proceeds from this financing will be used to make an equity contribution of
approximately $550 million in Edison Mission Midwest Holdings which, together with cash on hand, will be used to repay Edison Mission Midwest Holdings' $781 million indebtedness due on
December 11, 2003. The remaining net proceeds from this financing will be used to repay indebtedness of a foreign subsidiary under the Coal and CapEx facility guaranteed by EME. Mission Energy
Holdings International owns substantially all of EME's international operations, through its subsidiary, MEC International B.V. The commitment letter provides that collateral for this financing
includes a pledge of:



In
addition to the pledges of collateral, the commitment letter provides for guarantees of the loan by a number of EME domestic subsidiaries, including a guarantee by Edison Mission
Finance Co., which will pledge its receivable from EME Homer City Generation L.P. under a revolving loan agreement (under which $499 million was outstanding at September 30, 2003) as
security for such guarantee. The commitment letter also provides for:



The
commitment letter provides that Mission Energy Holdings International will covenant to prepay the indebtedness in an amount equal to the net after tax proceeds from any international
asset

40

---

sales
when such proceeds exceed $50 million, from certain issuances of indebtedness and equity, and from specified domestic asset sales when such proceeds exceed $200 million. In certain
circumstances, prepayment of indebtedness will be required in an amount equal to 100% of net after tax proceeds from the sale of certain of the domestic subsidiary guarantors of such indebtedness.

In
addition, the commitment letter provides for maintenance of a minimum twelve month interest coverage ratio beginning March 2004. Funding of this loan is subject to completion
of definitive documentation and a number of closing conditions, including obtaining certain consents and required corporate authorizations by EME and Mission Energy Holding Company. Completion of this
loan is subject to uncertainty and, accordingly, there is no assurance that definitive documentation will be completed and the closing conditions will be fulfilled.

A
failure to repay, extend or refinance the Edison Mission Midwest Holdings $781 million obligation is likely to result in a default under the Mission Energy Holding Company
senior secured notes and term loan. These events could make it necessary for Mission Energy Holding Company or EME, or both, to file a petition for reorganization under Chapter 11 of the United
States Bankruptcy Code. EME's independent accountants' audit opinion for the year ended December 31, 2002 contains an explanatory paragraph that indicates the consolidated financial statements
have been prepared on the basis that EME will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises
substantial doubt about EME's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this
uncertainty.

Credit Ratings

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

Moody's Rating

S&P RatingEdison Mission Energy

B2

BEdison Mission Midwest Holdings

Ba3

BEdison Mission Marketing & Trading

Not Rated

B


On October 28, 2003, Standard & Poor's Ratings Service downgraded EME's senior unsecured credit rating to B from BB-.
Standard & Poor's also lowered the credit ratings of EME's wholly owned indirect subsidiaries, Edison Mission Midwest Holdings (syndicated loan facility to B from BB-) and Edison
Mission Marketing & Trading (corporate credit rating to B from BB-). Standard & Poor's placed the ratings of all these entities on CreditWatch with negative implications. In
addition, Moody's Investors Service has assigned a negative rating outlook for EME and Edison Mission Midwest Holdings.

These
ratings actions did not trigger any defaults under EME's credit facilities or those of the other affected entities. See "Credit Ratings of Edison Mission Midwest Holdings" for a
discussion of the impact of the ratings action on Edison Mission Midwest Holdings.

The
credit ratings of EME are below investment grade and, accordingly, EME has agreed to provide collateral in the form of cash and letters of credit for the benefit of counterparties
for its price risk management and domestic trading activities related to accounts payable and unrealized losses ($40 million as of October 31, 2003). EME has also provided collateral for
a portion of its United Kingdom trading activities. To this end, EME's subsidiary, Edison Mission Operation and Maintenance Limited, has obtained a cash collateralized credit facility, under which
letters of credit totaling £19 million have been issued as of October 31, 2003.

EME
anticipates that sales of power from its Illinois Plants, Homer City facilities and First Hydro plants in the United Kingdom may require additional credit support, depending upon
market conditions and the strategies adopted for the sale of this power. Changes in forward market prices and

41

---

margining
requirements could further increase the need for credit support for the price risk management and trading activities related to these projects. EME currently projects the potential working
capital required to support its price risk management and trading activity to be between $100 million and $200 million from time to time.

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

Credit Ratings of Edison Mission Midwest Holdings

As a result of Edison Mission Midwest Holdings' credit rating being below investment grade since October 2002, provisions in the agreements binding on
Edison Mission Midwest Holdings and Midwest Generation have restricted the ability of Edison Mission Midwest Holdings to make distributions to its parent company, thereby eliminating distributions to
EME. The provisions in the agreements binding on Edison Mission Midwest Holdings required it to deposit, on a quarterly basis, 100% of its excess cash flow as defined in the agreements into a cash
flow recapture account held and maintained by the collateral agent. In accordance with these provisions, Edison Mission Midwest Holdings deposited $78 million into the cash flow recapture
account as of September 30, 2003. In October 2003, Edison Mission Midwest Holdings deposited an additional $168 million based on the calculation of excess cash flow for the third
quarter ended September 30, 2003. The funds in the cash flow recapture account were to be used only to meet debt service obligations of Edison Mission Midwest Holdings if funds were not
otherwise available from working capital.

As
a result of the October 28, 2003 Standard & Poor's downgrade of Edison Mission Midwest Holdings to B from BB-, the cash on deposit in the cash flow recapture
account ($246 million) related to Edison Mission Midwest Holdings' indebtedness was required to be used to prepay that indebtedness, with the amount of such prepayment applied ratably to the
$911 million and $808 million tranches thereof. Therefore, on October 29, 2003, $130 million from the cash flow recapture account was applied to the $911 million
tranche, and $116 million to the $808 million tranche, thereby reducing Edison Mission Midwest Holdings' debt obligations to $781 million and $692 million, respectively. In
the future, so long as Edison Mission Midwest Holdings' ratings remain at the current level or lower, amounts of excess cash flow deposited in the cash flow recapture account at the end of each
calendar quarter will be used upon deposit to prepay, pro rata, amounts then outstanding under these bank facilities. There was no change to the cost of borrowings for Edison Mission Midwest Holdings
as a result of the downgrade.

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

Credit Rating of Edison Mission Marketing & Trading

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

42

---

include
a requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all of the output
from the Homer City facilities through Edison Mission Marketing & Trading, which has a below investment grade credit rating, and EME Homer City is not rated. Therefore, in order for EME to
continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to permit EME Homer City to sell
directly into the market or through Edison Mission Marketing & Trading; or (2) Edison Mission Marketing & Trading must provide assurances of performance consistent with the
requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participant that will allow EME Homer City to enter into such sales,
under specified conditions, through December 31, 2004. EME Homer City continues to be in compliance with the terms of the consent, although as a result of the recent downgrade of Edison Mission
Marketing & Trading's corporate credit rating to B from BB-, the consent is now revocable. The owner participant has not indicated that it intends to revoke the consent; however,
there can be no assurance that it will not do so in the future. Revocation of the consent would not affect trades between Edison Mission Marketing & Trading and EME Homer City that had been
entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City facilities into the PJM market at any time on a spot-market basis. See
"Market Risk ExposuresHomer City Facilities."

Corporate Liquidity

EME has a $212 million corporate credit facility that expires on September 17, 2004. At September 30, 2003, EME had borrowing capacity of
$107 million and corporate cash and cash equivalents of $158 million.

Cash
distributions from EME's subsidiaries and partnership investments, tax-allocation payments from Edison International and unused capacity under its corporate credit
facility represent EME's major sources of liquidity to meet its cash requirements. EME expects its cash requirements during the next twelve months to be primarily comprised of:



The
timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "Historical Distributions Received by Edison Mission
EnergyRestricted Assets of EME's Subsidiaries." Also see "Risk Factors" in the Management's Discussion and Analysis of Results of Operations and Financial Condition included
in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2002. In addition, the right of EME to receive tax-allocation payments, and the
timing and amount of tax-allocation payments received by EME are subject to factors beyond EME's control. See "Intercompany Tax-Allocation Payments." If EME's
corporate credit facility is not refinanced or additional financing is not obtained on or before September 17, 2004, EME's ability to provide credit support for bilateral contracts for power
and fuel related to its merchant energy operations will be severely limited. If EME is unable to provide such credit support, this will reduce the number of counterparties willing to enter into
bilateral contracts with EME's subsidiaries, thus requiring EME's subsidiaries to rely on short-term markets instead of bilateral contracts. Furthermore, if this situation occurs, EME may
not be able to meet margining requirements if forward prices for power increase significantly. Failure to meet a margining

43

---

requirement
would permit the counterparty to terminate the related bilateral contract early and demand immediate payment of damages incurred by reason of such termination.

EME's
corporate credit facility provides credit available in the form of cash advances or letters of credit. At September 30, 2003, $105 million of letters of credit were
outstanding under Tranche B. In addition to the interest payments, EME pays a facility fee determined by its long-term credit ratings (1.00% at September 30, 2003) on the entire
credit facility independent of the level of borrowings.

Under
the credit agreement governing its credit facility, EME has agreed to maintain an interest coverage ratio that is based on cash received by EME, including
tax-allocation payments, cash disbursements and interest paid. At September 30, 2003, EME met this interest coverage ratio. The interest coverage ratio in the
ring-fencing provisions of EME's certificate of incorporation and bylaws remains relevant for determining EME's ability to make distributions. See "Interest Coverage Ratio."

EME
has entered into sale agreements with third parties for its interests in the Gordonsville project and a development project in Thailand, which are expected to be completed prior to
December 31, 2003. EME is considering the sale of additional investments, including its interests in the EcoEléctrica and Brooklyn Navy Yard projects and in Four Star Oil & Gas,
and plans to consider the sale of some or all of its international operations depending on, among other things, market prices. Management has not committed to the sale of any specific project other
than the Gordonsville project and the development project in Thailand. There is no assurance that EME will complete the sale of the assets mentioned above, or any other assets, and no assurance that
any sales completed will be on terms that recover EME's investment in these projects.

Discussion of Historical Cash Flow

Cash Flows From Operating Activities

Net cash provided by operating activities:

Nine Months Ended
September 30,2003

2002(in millions)Continuing operations

$
490

$
556Discontinued operations


(1
)

61$
489

$
617


The lower operating cash flow from continuing operations in the first three quarters of 2003, compared to the first three quarters of 2002,
reflects lower tax-allocation payments received from Edison International in 2003. EME received $89 million and $368 million in tax-allocation payments from
Edison International during the first nine months of 2003 and 2002, respectively. For further discussion on the tax-allocation payments, see "Intercompany
Tax-Allocation Payments." Distributions from unconsolidated affiliates during the first nine months of 2003 were higher than the first nine months of 2002 primarily due to receipt of
$151 million from the completion of the Sunrise project financing in September 2003. Distributions from unconsolidated affiliates in 2002 reflect the collection of past due accounts
receivable from California utilities, arising from the California energy crisis, by EME's investments in California qualifying facilities which amounts were then distributed to their partners. The
change in operating cash flow from continuing operations in the first three quarters of 2003 was also due to the timing of cash receipts and disbursements related to working capital items.

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 and
operating income from the Lakeland power plant during the first nine months of 2002.

44

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Cash Flows From Financing Activities

Net cash provided by (used in) financing activities:

Nine Months Ended
September 30,2003

2002(in millions)Continuing operations

$
85

$
(204
)Discontinued operations





(14
)$
85

$
(218
)


Cash provided by financing activities from continuing operations during the first three quarters of 2003 included $275 million in
borrowings used to finance the acquisition of the Taranaki power station by Contact Energy, EME's 51% owned subsidiary. Debt service payments of $76 million related to two of EME's subsidiaries
were made in 2003. In addition, EME repaid $31 million in September 2003 of debt obligations due from the acquisition of the Spanish Hydro project.

Cash
used in financing activities from continuing operations during the first three quarters of 2002 consisted of payment at maturity of $100 million of senior notes, net payments
of $80 million on EME's corporate credit facility, $44 million related to debt service payments of one of EME's subsidiaries, and payments of $86 million from its Coal and Capex
facility. In addition, a wholly owned subsidiary borrowed $84 million under a note purchase agreement in January 2002. EME also received $54 million from a swap agreement with a
bank related to lease payments for its Homer City facilities.

Cash
used in financing activities from discontinued operations in 2002 reflects repayments of long-term debt from the Lakeland power plant.

Cash Flows From Investing Activities

Net cash used in investing activities:

Nine Months Ended
September 30,2003

2002(in millions)Continuing operations

$
(417
)
$
(122
)Discontinued operations


5


1$
(412
)
$
(121
)


Cash used in investing activities from continuing operations during the first three quarters of 2003 included $275 million paid by Contact
Energy for the acquisition of the Taranaki power station during the first quarter of 2003 and $60 million in equity contributions to the Sunrise and CBK projects. EME invested
$105 million in the first nine months of 2003 in new plant and equipment principally related to the Illinois Plants, the Homer City facilities and Contact Energy.

Cash
used in investing activities from continuing operations during the first three quarters of 2002 included $80 million paid for the purchase of a power sales agreement held by
a third party. EME invested $516 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 EME's Master Turbine Lease with funds from restricted cash of $61 million. Included in the first three quarters of 2002 investing activities was $86 million of
restricted cash used to purchase the three turbines and satisfy EME's obligation related to the termination of EME's Master Turbine Lease, thereby reducing EME's restricted cash account. In addition,
included in capital expenditures during

45

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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 EME. Through the first three quarters of 2002, $18 million was paid in equity contributions for Phase 2 of the Sunrise project. EME received proceeds of $44 million from the
sales of its 50% interests in the Commonwealth Atlantic and James River projects and its 30% interest in the Harbor project during the first quarter of 2002. In addition, EME received
$78 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 EME's lease payment obligations.

Historical Distributions Received By Edison Mission Energy

The following table is presented as an aid in understanding the cash flow of EME and its various subsidiary holding companies which depend on distributions from
subsidiaries and affiliates to fund general and administrative costs and interest costs of recourse debt. Distributions for the first nine months of each year are not necessarily indicative of annual
distributions due to the seasonal fluctuations in EME's business.

Nine Months Ended
September 30,2003

2002(in millions)Distributions from Consolidated Operating Projects:EME Homer City Generation L.P. (Homer City facilities)(1)

$
102

$
Holding companies of other consolidated operating projects


87


21Distributions from Unconsolidated Operating Projects:Edison Mission Energy Funding Corp. (Big 4 Projects)(2)


74


112Four Star Oil & Gas Company


15


21Holding companies of other unconsolidated operating projects(3)


112


66Total Distributions

$
390

$
220


---

Total distributions to EME increased due to:



46

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Partially
offset by:



Restricted Assets of EME's Subsidiaries

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

Edison Mission Midwest Holdings Co. (Illinois Plants)

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

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

47

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Powerton
and Joliet leases. During the 12 months ended September 30, 2003, the historical debt service coverage ratio was 2.31 to 1 and the debt-to-capital ratio
was 0.52 to 1.

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

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

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



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

During
the 12 months ended September 30, 2003, the senior rent service coverage ratio was 4.53 to 1.

First Hydro Holdings

A subsidiary of First Hydro Holdings, First Hydro Finance plc, has issued £400 million of Guaranteed Secured Bonds due in 2021. In order to
make a distribution, First Hydro Finance must be in compliance with the covenants specified in its bond indenture, including an interest coverage ratio. When measured for the twelve-month period ended
December 31, 2002, First Hydro Holdings met the interest coverage ratio and made a distribution of $18 million on May 7, 2003. When measured for the twelve-month period ended
June 30, 2003, First Hydro Holdings' interest coverage ratio was 1.49 to 1.

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

48

---

its
receipt of the trustee's March 14, 2003 letter, First Hydro Finance had not received a response from the trustee to its August 29, 2000 notice. First Hydro Finance will dispute any
attempt to have the early redemption option deemed applicable due to NETA implementation.

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

Edison Mission Energy Funding Corp. (Big 4 Projects)

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



The
debt service coverage ratio is determined primarily based upon the amount of distributions received by the guarantors from the Big 4 projects during the relevant quarter divided by
the debt service (principal and interest) on Edison Mission Energy Funding's notes and bonds paid or due in the relevant quarter. During the 12 months ended September 30, 2003, the debt
service coverage ratio was 2.55 to 1. Although the credit ratings of Edison Mission Energy Funding's notes and bonds are below investment grade, this has no effect on the ability of the guarantors to
make distributions to EME.

CBK Project

EME holds a 50% interest in CBK Power Co Ltd. CBK Power operates under a 25-year build-rehabilitate-operate-transfer agreement with National
Power Corporation for the 756 MW Caliraya-Botocan-Kalayaan hydro electric complex, located in the Republic of the Philippines, which EME refers to as the CBK project. On April 23, 2003, the
President of the Republic of the Philippines signed into law the 2003 General Appropriations Act, which included a provision that stopped payments for two of the Kalayaan units by agencies of the
Philippine government to CBK Power until specific conditions were met. On May 22, 2003, CBK Power and National Power Corporation, with the concurrence of Power Sector Assets and Liabilities
Management Corporation (PSALM), entered into a settlement agreement. PSALM is a Philippine government-owned entity with responsibility for the electric power

49

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sector.
The settlement agreement provides for specific concessions to National Power Corporation which have been deemed by the parties to satisfy the conditions included in the General Appropriations
Act. The Secretary of Management and Budget confirmed to National Power Corporation that payments could be made to CBK Power using funds provided by the 2003 General Appropriations Act based on
National Power Corporation's determination that the requirements of those provisions have been met. National Power Corporation has cleared all arrears owing to CBK Power and has made all payments
since the signing of the settlement agreement in a timely manner. CBK Power has obtained its lender's consent to the modification to the build-rehabilitate-operate-transfer agreement.

Interest Coverage Ratio

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



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

50

---

The
following table sets forth the major components of the interest coverage ratio for the twelve months ended September 30, 2003 and the year ended December 31, 2002:

September 30,
2003

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

$
170

$
294Homer City


142


51First Hydro


(30
)

47Other consolidated operating projects


170


158Price risk management and energy trading


13


16Distributions from unconsolidated Big 4 projects


100


137Distributions from other unconsolidated operating projects


159


120Interest income


6


8Operating expenses


(139
)

(139
)Total funds flow from operations

$
591

$
692Interest Expense:From obligations to unrelated third parties

$
168

$
178From notes payable to Midwest Generation


113


115Total interest expense

$
281

$
293Interest Coverage Ratio


2.10


2.36


---

The
major factors affecting funds flow from operations during the twelve months ended September 30, 2003, compared to the year ended December 31, 2002, were:



51

---



Interest
expense decreased by $12 million for the twelve months ended September 30, 2003, compared to the year ended December 31, 2002 due to a lower average debt
balance.

EME's
interest coverage ratio for the twelve months ended September 30, 2003 was 2.10 to 1. Accordingly, under the "ring-fencing" provisions of EME's certificate of
incorporation and bylaws, without unanimous board approval, EME is not permitted to pay dividends in the fourth quarter of 2003. EME did not pay or declare any dividends to Mission Energy Holding
Company during the first nine months of 2003.

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

Edison Mission Energy Recourse Debt to Recourse Capital Ratio

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

|Financial Ratio                         |  | Covenant                    |  | Actual at September 30, 2003 |  | Description                                                                                                                                                                            
|--------------------------------------- |  | --------------------------- |  | ---------------------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Recourse Debt to Recourse Capital Ratio |  | Less than or equal to 67.5% |  | 61.6%                        |  | Ratio of (a) senior recourse debt to (b) sum of (i) shareholder's equity per EME's balance sheet adjusted by comprehensive income after December 31, 1999,plus(ii) senior recourse debt

52

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Discussion of Recourse Debt to Recourse Capital Ratio

The recourse debt to recourse capital ratio of EME at September 30, 2003 and December 31, 2002 was calculated as follows:

September 30,
2003

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

$
108

$
140Senior Notes


1,600


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


1,441


1,452Coal and Capex Facility


188


182Other





30Total Recourse Debt to EME

$
3,337

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

$
2,084

$
2,066Recourse Capital(3)

$
5,421

$
5,470Recourse Debt to Recourse Capital Ratio


61.6
%

62.2
%


---

During the nine months ended September 30, 2003, the recourse debt to recourse capital ratio decreased due to:



EME's
indirect subsidiary, Midwest Generation, reported in its second quarter report on Form 10-Q an asset impairment charge of $475 million, after tax, related
to the 2,698 MW gas-fired Collins Station. The impairment charge resulted from a write-down of the book value of capitalized assets related to the Collins Station from
$858 million to an estimated fair market value of $78 million. The impairment charge by Midwest Generation is not reflected in the operating results of EME because the lease related to
the Collins Station is treated in EME's financial statements as an operating lease and not as an asset and, therefore, is not subject to impairment for accounting purposes. EME is evaluating a number
of debt restructuring alternatives, some of which could result in the consolidation of the Collins Station and recognition of a loss in the consolidated accounts of EME. A restructuring alternative
that results in the consolidation of the Collins Station would require EME to obtain modifications to net worth covenants contained in its credit facilities and the guarantee it provides to the owner
participants in the Powerton and Joliet sale-leaseback.

53

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Subsidiary Financing Plans

The estimated capital and construction expenditures of EME's subsidiaries for the fourth quarter of 2003 are $21 million. These expenditures are planned to
be financed by existing subsidiary credit agreements and cash generated from their operations, except with respect to the Homer City project. Under the Homer City sale-leaseback
agreements, EME has committed to provide funds for capital expenditures needed to complete the Homer City environmental improvement project. EME expects to contribute $24 million in 2003 to
fund the completion of this project, of which $21 million was contributed during the first nine months of 2003.

Edison Mission Midwest Holdings

As a result of the downgrade of the credit rating of Edison Mission Midwest Holdings by Standard & Poor's (see "Credit Ratings of Edison
Mission Midwest Holdings"), Edison Mission Midwest Holdings repaid $246 million on October 29, 2003 under its credit agreements with commercial lenders from funds deposited in the cash
flow recapture account. The following table summarizes Edison Mission Midwest Holdings' debt maturities (in millions):

At September 30,
2003

Paid From
Cash Flow
Recapture Account

Balance After
Payment

Due Date$
911

$
(130
)
$
781

December 11, 2003808


(116
)

692

December 15, 2004$
1,719

$
(246
)
$
1,473


In
addition, Edison Mission Midwest Holdings has a $150 million working capital facility (unused) which is scheduled to expire on December 15, 2004. Edison Mission Midwest
Holdings has $781 million of debt maturing on December 11, 2003 which will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings does not have sufficient cash to
repay this indebtedness when due.

On
November 13, 2003, EME's subsidiary, Mission Energy Holdings International, Inc. received a commitment letter from Citigroup, Credit Suisse First Boston,
JPMorganChaseBank and Lehman Brothers Inc. to provide a three-year, $700 million secured loan intended to provide bridge financing to asset sales, including the sale of some or all
of its international operations, depending upon, among other things, market prices. Subject to completion, the net proceeds from this financing will be used to make an equity contribution of
approximately $550 million in Edison Mission Midwest Holdings which, together with cash on hand, will be used to repay Edison Mission Midwest Holdings' $781 million indebtedness due on
December 11, 2003. The remaining net proceeds from this financing will be used to repay indebtedness of a foreign subsidiary under the Coal and CapEx facility guaranteed by EME. Funding of this
loan is subject to completion of definitive documentation and a number of closing conditions, including obtaining certain consents and required corporate authorizations by EME and Mission Energy
Holding Company. Completion of this loan is subject to uncertainty and, accordingly, there is no assurance that definitive documentation will be completed and the closing conditions will be fulfilled.
For additional discussion see "Liquidity and Capital ResourcesFinancing Plan for $781 Million Debt Maturity."

Loy Yang B

On October 31, 2003, an affiliate of EME entered into an A$65 million subordinated amortizing facility consisting of a six-year
A$50 million letter of credit facility and a six-year A$15 million amortizing cash facility. The letter of credit issued under the letter of credit facility replaces an
A$50 million letter of credit outstanding under EME's corporate credit facility at September 30, 2003, which was due to expire in September 2004, thereby increasing EME's
borrowing capacity under its

54

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corporate
credit facility. Drawings under the amortizing cash facility will be used to prepay indebtedness of EME coming due in 2004.

Intercompany Tax-Allocation Payments

EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in
tax-allocation payments with other subsidiaries of Edison International. These arrangements depend on Edison International continuing to own, directly or indirectly, at least 80% of the
voting power of the stock of EME and at least 80% of the value of such stock. A foreclosure by Mission Energy Holding Company's financing parties on EME's stock would make EME ineligible to
participate in the tax-allocation payments. The arrangements are subject to the terms of tax allocation and payment agreements among Edison International, Mission Energy Holding Company,
EME, and other Edison International subsidiaries. The agreements to which EME is a party may be terminated by the immediate parent company at any time, by notice given before the first day of the
first tax year with respect to which the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year beginning prior to the notice.
EME has historically received tax-allocation payments related to domestic net operating losses incurred by EME. The right of EME to receive and the amount and timing of
tax-allocation payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the
consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its subsidiaries, and other subsidiaries of Edison
International and specific procedures regarding allocation of state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison
International group generates sufficient taxable income in order to be able to utilize EME's tax losses in the consolidated income tax returns for Edison International and its subsidiaries. During the
nine-month period ended September 30, 2003, EME received $89 million in tax-allocation payments from Edison International. In the future, based on the application
of the factors cited above, EME may be obligated during periods it generates taxable income to make payments under the tax-allocation agreements.

Contractual Obligations

Chicago In-City Obligation

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

Fuel Supply Contracts

Midwest Generation has entered into additional fuel purchase agreements with several third-party suppliers during the first nine months of 2003. Midwest
Generation's aggregate fuel purchase commitments under these agreements are currently estimated to be $39 million for 2003, $199 million for 2004, $195 million for 2005,
$89 million for 2006, and $91 million for 2007.

Gas Transportation Agreements

In April 2003, the Sunrise project assumed EME's obligations under a gas transportation agreement, thereby reducing EME's contractual commitments to
transport natural gas. EME's share of the commitment to pay minimum fees under its remaining gas transportation agreement, which has a

55

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term
of 15 years, is currently estimated to be $2 million for the fourth quarter of 2003; $8 million for 2004; $8 million for 2005; $8 million for 2006; and
$8 million for 2007.

MARKET RISK EXPOSURES

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

Commodity Price Risk

EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored to ensure compliance
with EME's risk management policies. Policies are in place which define risk tolerances for each EME regional business unit. Procedures exist which allow for monitoring of all commitments and
positions with regular reviews by a risk management committee. In order to provide more predictable earnings and cash flow, EME may hedge a portion of the electric output of its merchant plants, the
output of which is not committed to be sold under long-term contracts. When appropriate, EME manages the spread
between electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives. There is no assurance that contracts to hedge changes in market
prices will be effective.

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



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

Americas

EME performs a "value at risk" analysis in its daily business to measure, monitor and control its overall market risk exposure in respect of its Illinois Plants,
its Homer City facilities, its Four Star investment, and its proprietary positions. The use of value at risk allows management to aggregate

56

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overall
commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible loss over a given time interval, under normal market conditions, at a
given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements this approach with the use of stress testing and
worst-case scenario analysis for key risk factors, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been
accurately identified, measured and/or mitigated.

Electric
power generated at EME's domestic merchant plants is generally sold under bilateral arrangements with utilities and power marketers under short-term transactions
with terms of two years or less or, in the case of the Homer City facilities, to the PJM and/or the New York Independent System Operator (NYISO) as well as utilities and power marketers. As discussed
further below, beginning in 2003, EME has been selling a significant portion of the power generated from its Illinois Plants into wholesale energy markets.

Illinois Plants

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

Under
each of the power purchase agreements, Exelon Generation, upon notice by given dates, had the option to terminate each agreement with respect to all or a portion of the units
subject to it. As a result of notices given in 2002, effective January 1, 2003, Exelon Generation released 4,548 MW of Midwest Generation's generating capacity from the power purchase
agreements, thus increasing Midwest Generation's reliance on sales into the wholesale markets. As a result, 4,739 MW of capacity remain subject to power purchase agreements with Exelon Generation in
2003.

Exelon
Generation notified Midwest Generation on June 25, 2003 of the exercise of its option to contract 687 MW of capacity and the associated energy output (out of a possible
total of 1,265 MW subject to the option) during 2004 from Midwest Generation's coal-fired units in accordance with the terms of the existing power purchase agreement related to Midwest
Generation's coal-fired generation units. As a result, 578 MW of the capacity of these units will no longer be subject to the power purchase agreement beginning January 1, 2004. The
notification received from Exelon Generation has no effect on its commitments to purchase capacity from these generating units for the balance of 2003. For 2004, Exelon Generation will have 2,383 MW
of capacity related to its coal-fired generation units under contract with Midwest Generation.

On
October 1, 2003, Exelon Generation notified Midwest Generation of the exercise of its option to retain under a power purchase agreement for calendar year 2004 the 1,084 MW of
capacity and energy from Midwest Generation's Collins Station currently under contract for calendar year 2003. Exelon Generation also exercised its option to release from a related power purchase
agreement 302 MW of capacity and energy (out of a possible total of 694 MW subject to the option) from Midwest Generation's natural gas and oil-fired peaking units, thereby retaining under
that contract 392 MW of the capacity and energy of such units for calendar year 2004. The notification received from Exelon Generation has no effect on its commitments to purchase capacity from these
peaking units for the balance of 2003.

57

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As
a result of notices given in 2003, as described above, effective January 1, 2004, Exelon Generation released an additional 880 MW of generating capacity, leaving 3,859 MW of
capacity remaining subject to the power purchase agreements with Exelon Generation in 2004.

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

During
2003 and 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois Plants are expected to be "wholesale customer" and
"over-the-counter." The most liquid over-the-counter markets in the Midwest region are sales into the control area of Cinergy, referred to as "Into
Cinergy," and, to a lesser extent, sales into the control area of Commonwealth Edison, referred to as "Into ComEd" (due to geographic proximity, "Into ComEd" has been the primary market for Midwest
Generation). "Into Cinergy" and "Into ComEd" are bilateral markets for the sale or purchase of electrical energy for future delivery. Performance of transactions in these markets is subject to
contracts that generally provide for liquidated damages supported by a variety of credit requirements, which may include independent credit assessment, parent company guarantees, letters of credit,
and cash margining arrangements.

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

|                   |  | Into ComEd* |       | Into Cinergy*
|------------------ |  | ----------- | ----- | -------------
|
|
|January            |  | $           | 42.62 |              
|February           |  |             | 54.43 |              
|March              |  |             | 47.96 |              
|April              |  |             | 39.12 |              
|May                |  |             | 29.59 |              
|June               |  |             | 30.27 |              
|July               |  |             | 41.63 |              
|August             |  |             | 48.75 |              
|September          |  |             | 27.44 |              
|                   |  |             |       |              
|Nine-Month Average |  | $           | 40.20 |              
|                   |  |             |       |              

---

58

---

The following table sets forth forward market prices for energy per megawatt-hour as quoted for sales "Into ComEd" and "Into Cinergy" at September 30, 2003. These
forward prices will continue to fluctuate as a result of a number of factors, including gas prices, electricity demand, which is also affected by economic growth, and the amount of existing and
planned power plant capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward market prices.

|                         |          | Into ComEd* |       | Into Cinergy*
|------------------------ | -------- | ----------- | ----- | -------------
|
|
|2003                     |          |             |       |              
|                         | October  |             | $     | 24.00        
|                         | November |             |       | 27.30        
|                         | December |             |       | 31.10        
|2004 Calendar "strip"(2) |          |             | 33.64 |              

---

Midwest
Generation intends to hedge a portion of its merchant portfolio risk through its marketing affiliate. To the extent it does not do so, the unhedged portion will be subject to the
risks and benefits of spot market price movements. The extent to which Midwest Generation will hedge its market price risk through forward over-the-counter sales depends on
several factors. First, Midwest Generation will evaluate over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared
to assuming the risk associated with spot market sales. Second, Midwest Generation's ability to enter into hedging transactions will depend upon its and its marketing affiliate's credit capacity and
upon the over-the-counter forward sales markets having sufficient liquidity to enable Midwest Generation to identify counterparties who are able and willing to enter into
hedging transactions with it. Due to factors beyond Midwest Generation's control, market liquidity 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. See "Credit Risk," below.

In
addition to the prevailing market prices, Midwest Generation's ability to derive profits from the sale of electricity from the released units will be affected by the cost of
production, including costs incurred
to comply with environmental regulations. The costs of production of the released units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the
released units is expected to vary from unit to unit. In this regard, Midwest Generation suspended operations of Will County Units 1 and 2 and Collins Station Units 4 and 5 at the end of 2002 pending
improvement in market conditions. If market conditions were to be depressed for an extended period of time, Midwest Generation would need to consider decommissioning Will County Units 1 and 2, which
would result in a charge against income. Collins Station Units 4 and 5 are subject to a long-term lease which requires that for the term of the lease, these units be maintained in
condition for return to service, should market conditions improve. Thus, in the absence of an agreement with the lessor under the lease, Midwest Generation cannot decommission these units.

In
addition to the price risks described previously, Midwest Generation's ability to transmit energy to counterparty delivery points to consummate spot sales and hedging transactions may
also be affected

59

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by
transmission service limitations and constraints and new standard market design proposals proposed by and currently pending before the Federal Energy Regulatory Commission, or the FERC. Although
the FERC and the relevant industry participants are working to minimize such issues, Midwest Generation cannot determine how quickly or how effectively such issues will be resolved. Currently,
transmission must be obtained from Commonwealth Edison under its open-access tariff filed with the FERC. Such transmission procurement is expected to continue throughout 2003. There is
considerable uncertainty about Commonwealth Edison's integration in PJM. For further details see "Regulatory Matters." EME is unable to predict the outcome of these efforts or the effect
of any final integration configuration on the markets into which Midwest Generation sells its power.

Homer City Facilities

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

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

24-Hour PJM
Historical Energy Prices*2003

2002January

$
36.56

$
20.52February


46.13


20.62March


46.85


24.27April


35.35


25.68May


32.29


21.98June


27.26


24.98July


36.55


30.01August


39.27


30.40September


28.71


29.00Nine-Month Average

$
36.55

$
25.27


---

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

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

60

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price
risk management activities use to enter into forward contracts. EME's revenues with respect to such forward contracts include:



Under
the PJM market design, locational marginal pricing (sometimes referred to as LMP) has the effect of raising prices at those delivery points affected by transmission congestion.
During the past 12 months, an increase in transmission congestion at delivery points east of the Homer City facilities has resulted in prices at the PJM West Hub (which includes delivery points
east of the Homer City facilities) being higher than those at the Homer City busbar. Thus, while forward prices at PJM West Hub have historically been higher than the prices at the Homer City busbar
by less than 5%, increased congestion during the last 12 months at delivery points east of the Homer City facilities has resulted in prices at PJM West Hub being on average 8% higher than those
at the Homer City busbar.

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

The
following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at September 30, 2003:

24-Hour PJM West
Forward Energy Prices*2003October

$
30.82November


28.82December


32.272004 Calendar "strip"(1)


32.84


---

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

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Europe

United Kingdom

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

The
electricity trading arrangements introduced in March 2001 provide, among other things, for the establishment of a range of voluntary short-term power exchanges and
brokered markets operating from a year or more in advance to 1 hour prior to the delivery or receipt of power. In the final hour after the notification of all contracts, the system operator can
accept bids and offers in the Balancing Mechanism to balance generation and demand and resolve any transmission constraints. There is a mandatory settlement process for recovering imbalances between
contracted and metered volumes with strong incentives for being in balance, and a Balancing and Settlement Code Panel to oversee governance of the Balancing Mechanism. The system operator can also
purchase system reserve and response services to maintain the quality of the electrical supply directly from generators (generally referred to as "ancillary services"). Ancillary services contracts
typically run for up to a year and can consist of both fixed amounts and variable amounts represented by prices for services that are only paid for when actually called upon by the grid operator. A
key feature of the trading arrangements is the requirement for firm physical delivery, which means that a generator must deliver, and a consumer must take delivery of, its net contracted positions or
pay for any energy imbalance at the imbalance prices calculated by the system operator based on the prices of bids and offers accepted in the Balancing Mechanism. This provides an incentive for
parties to contract in advance and for the development of forwards and futures markets. Under these arrangements, there has been an increased emphasis on credit quality, including the need for parent
company guarantees or letters of credit for companies below investment grade.

The
wholesale price of electricity has decreased significantly in recent years. The reduction has been driven principally by surplus generating capacity and increased competition. During
2002 and the first quarter of 2003, there was further downward pressure on wholesale prices but some recovery in the peak/off peak differentials for the upcoming winter period. This recovery in the
market continued during the summer with higher-than-expected demand and with a further increase in forward prices for the winter reflecting an expected reduction in the excess
of available physical generating capacity over expected electrical demand.

Despite
the difficult market conditions, First Hydro has continued to meet the interest coverage ratios specified in its bond financing documents, and to meet its half yearly interest
payments without recourse to the project's debt service reserve. EME believes that if market and trading conditions experienced thus far in 2003 are sustained, First Hydro will continue to be
compliant with the requirements of its bond financing documents. This compliance is, however, subject to market conditions for electric energy and ancillary services, which are beyond EME's control.

Asia Pacific

Australia

The Loy Yang B plant and the Valley Power Peaker project sell electrical energy through a centralized electricity pool, which provides for a system of generator
bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and
administrator of the pool, determines a spot 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

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State
Government of Victoria, Australia guarantees the State Electricity Commission of Victoria's obligations under the State Hedge. From January 2003 to July 2014, approximately 77% of
the Loy Yang B plant output sold is hedged under the State Hedge. From August 2014 to October 2016, approximately 56% of the Loy Yang B plant output sold is hedged under the State Hedge.
Additionally, the Loy Yang B plant and the Valley Power Peaker project have entered into a number of derivative contracts to mitigate further against price volatility inherent in the electricity pool.
These contracts consist of fixed forward electricity contracts and/or cap contracts that expire on various dates through December 31, 2006.

New Zealand

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

The
New Zealand government released a government policy statement in December 2001, which called for the industry to rationalize the three existing industry codes, form a
single governance structure and address transmission investment and pricing issues. The industry was unable to agree on new rules to facilitate the government policy statement.

Subsequently,
in May 2003, the New Zealand government announced that it would establish a new governance body to be known as the Electricity Commission along with a set of rules
to govern the market. The industry was given the opportunity to comment on the new governance arrangements, with final submissions due in September 2003. The final decision on these
arrangements is pending.

During
the winter of 2003, wholesale electricity prices increased significantly in response to lower hydro inflows, higher demand and anticipated restrictions on the availability of
thermal fuel. The New Zealand government responded by calling for nationwide energy savings in the order of 10%. Recent rains and anticipated snowmelt have largely improved the earlier conditions with
wholesale electricity prices returning to more normal levels. The national energy savings program ended in July 2003.

However,
there are ongoing concerns that new investment in generation has not been forthcoming and that there is a significant risk that similar events may arise in subsequent years. As
a consequence the New Zealand government announced that it will take the following steps:



Submissions
have been made in respect of the policy, which are currently being considered by the New Zealand government. Final details of the policy were released in
September 2003, and it is expected that legislation will be passed by early next year.

The
New Zealand government announced in July 2003 that it would purchase a new 155 MW power plant before winter 2004 to increase electricity security. The plant is to be situated
at Whirinaki, Hawkes Bay. The Electricity Commission will be required to include this plant in its portfolio of reserve energy. The Whirinaki plant will be located on a site leased to the government
from Contact Energy and will also be operated under contract by Contact Energy.

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Credit Risk

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

To
manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME would record if its counterparties failed to perform
pursuant to the terms of their contractual obligations. EME has established controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever
possible to mitigate its exposure to counterparty risk. EME may require counterparties to pledge collateral when deemed necessary. EME tries to manage the credit in its portfolio based on credit
ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings and press releases, to guide it in the process of setting
credit levels, risk limits and contractual arrangements including master netting agreements. The credit quality of EME's counterparties is reviewed regularly by EME's risk management committee. In
addition to continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower credit exposure. Despite this, there can be no assurance that EME's
actions to mitigate risk will be wholly successful or that collateral pledged will be adequate.

EME
measures credit risk exposure from counterparties of its merchant energy activities by the sum of: (i) generally 60 days of accounts receivable, (ii) current
fair value of open positions, and (iii) a credit value at risk. EME's subsidiaries enter into master agreements and other arrangements in conducting price risk management and trading activities
which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME's credit risk exposure from counterparties is based on net exposure under
these agreements. The credit ratings supporting the credit risk exposure from counterparties of merchant energy activities at September 30, 2003 were as follows:

S&P Credit Rating

September 30, 2003(in millions)A or higher

$
85A-


23BBB+


87BBB


38BBB-


9Below investment grade(1)


12Total

$
254


---

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Exelon Generation accounted for 25% and 44% of EME's consolidated operating revenues for the first nine months of 2003 and 2002, respectively. The percentage is less in 2003 because a
smaller number of plants are subject to contracts with Exelon Generation. See "Market Risk ExposuresAmericasIllinois Plants." Any failure of Exelon Generation to make
payments to Midwest Generation under the power purchase agreements could result in a shortfall of cash available for Midwest Generation to meet its obligations. A default by Midwest Generation in
meeting its obligations could in turn have a material adverse effect on EME.

EME's
contracted power plants and the plants owned by unconsolidated affiliates in which EME owns an interest sell power under long-term power purchase agreements. Generally,
each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a long-term power purchase agreement, including a default as a result of a bankruptcy, would
likely have a material adverse effect on the operations of such power plant.

Interest Rate Risk

Interest rate changes affect the cost of capital needed to operate EME's projects and the lease costs under the Collins Station lease. EME has mitigated the risk
of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project
financings. Interest expense included $37 million and $27 million of additional interest expense for the nine months ended September 30, 2003 and 2002, respectively, as a result
of interest rate hedging mechanisms. EME has entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt.

The
fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's total long-term obligations
(including current portion) was $6.1 billion at September 30, 2003, compared to the carrying value of $6.4 billion.

Foreign Exchange Rate Risk

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

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

During
the first nine months of 2003, foreign currencies in Australia, New Zealand and the U.K. increased in value compared to the U.S. dollar by 20%, 12% and 3%, respectively
(determined by the change in the exchange rates from December 31, 2002 to September 30, 2003). The increase in value of these currencies was the primary reason for the foreign currency
translation gain of $69 million during the first nine months of 2003.

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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 February 2006. At September 30, 2003, the outstanding notional amount of the contracts totaled
$18 million and the fair value of the contracts totaled $(300) thousand.

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

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

Non-Trading Derivative Financial Instruments

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

September 30,
2003

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

$
(45
)
$
(48
)Interest rate options


(1
)

(2
)Commodity price:Electricity


(29
)

(100
)Cross-currency interest rate swaps


(49
)

(2
)


In
assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions based on the market conditions and associated
risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other
factors. The following table summarizes the maturities, the valuation method and the related fair value of EME's commodity price risk management assets and liabilities (as of September 30,
2003) (in millions):

|                                                   |  | Total Fair
Value |     | Maturity
<1 year |   | Maturity
1 to 3
years |  | Maturity
4 to 5
years |    | Maturity
>5 years |  
|-------------------------------------------------- |  | ---------------- | --- | ---------------- | - | --------------------- |  | --------------------- | -- | ----------------- | -
|Prices actively quoted                             |  | $                | 51  |                  | $ | 30                    |  | $                     | 21 |                   | $
|Prices based on models and other valuation methods |  |                  | (80 | )                |   | 12                    |  |                       | 6  |                   |  
|                                                   |  |                  |     |                  |   |                       |  |                       |    |                   |  
|Total                                              |  | $                | (29 | )                | $ | 42                    |  | $                     | 27 |                   | $
|                                                   |  |                  |     |                  |   |                       |  |                       |    |                   |  

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

Energy Trading Derivative Financial Instruments

EME's risk management and trading operations are conducted by its subsidiary, Edison Mission Marketing & Trading. As a result of a number of industry and
credit-related factors, Edison Mission Marketing & Trading has minimized its price risk management and trading activities not related to

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EME's
power plants or investments in energy projects. To the extent Edison Mission Marketing & Trading engages in trading activities, Edison Mission Marketing & Trading seeks to manage
price risk and to create stability of future income by selling electricity in the forward markets and, to a lesser degree, to generate profit from price volatility of electricity and fuels by buying
and selling these commodities in wholesale markets. EME generally balances forward sales and purchase contracts and manages its exposure through a value at risk analysis as described under
"Commodity Price Risk."

The
fair value of the commodity financial instruments related to energy trading activities as of September 30, 2003 and December 31, 2002, are set forth below (in
millions):

|            |  | September 30, 2003 |     | December 31, 2002
|----------- |  | ------------------ | --- | -----------------
|
|Electricity |  | $                  | 131 |                  
|Other       |  |                    |    |                  
|            |  |                    |     |                  
|Total       |  | $                  | 131 |                  
|            |  |                    |     |                  

The
change in the fair value of trading contracts for the quarter ended September 30, 2003, was as follows (in millions):

|Fair value of trading contracts at December 31, 2002  |  | $ | 92  |  
|----------------------------------------------------- |  | - | --- | -
|Net gains from energy trading activities              |  |   | 37  |  
|Amount realized from energy trading activities        |  |   | (33 | )
|                                                      |  |   |    
|Fair value of trading contracts at September 30, 2003 |  | $ | 96  |  
|                                                      |  |   |    

Quoted
market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated
electric utility that EME's subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME's subsidiary recorded these agreements at fair
value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance
the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of
September 30, 2003) (in millions):

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

Regulatory Matters

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

Currently,
power produced by the Illinois Plants not under contract with Exelon Generation is sold using transmission which must be obtained from Commonwealth Edison under its
open-access tariff filed with the FERC. In 2002, Commonwealth Edison applied to the FERC for approval to join PJM in conjunction with American Electric Power, thereby creating an enlarged,
contiguous regional

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transmission
organization encompassing a broad regional market. Approval of this application was granted by the FERC on April 1, 2003. Concurrently, the ability of American Electric Power to
join PJM has been brought into question by the enactment of legislation in Virginia requiring the approval of Virginia state authorities for any transfer of control from American Electric Power to PJM
of American Electric Power transmission assets located in Virginia. On April 16, 2003, Commonwealth Edison and PJM issued a joint press release stating that the integration of Commonwealth
Edison into PJM would proceed separately from that of American Electric Power, notwithstanding the absence of a direct transmission link owned by Commonwealth Edison between its service territory and
the existing PJM. In response to this announcement, EME and other affected parties filed with the FERC for clarification or rehearing of its April 1, 2003 order, and essentially contested the
appropriateness of Commonwealth Edison joining PJM on an "islanded" basis. The FERC clarified that a series of pre-conditions imposed by an order issued on July 31, 2002,
tentatively approving the stated decisions of Commonwealth Edison and American Electric Power to join PJM together, continue to be applicable to the separate application of Commonwealth Edison to join
PJM standing alone. Those conditions include (a) the elimination of multiple transmission rates between PJM and the Midwest Independent System Operator (Midwest ISO), which controls the
transmission markets surrounding the service territory of Commonwealth Edison, and (b) an agreement between PJM and the Midwest ISO regarding the management of operations across their "seams,"
which are required to be done in such a manner as to hold harmless utility customers of the Midwest ISO in Wisconsin and Michigan from the adverse effects of congestion and loop flows caused by the
membership of Commonwealth Edison in PJM. On August 1, 2003, Commonwealth Edison filed a notice of appeal of the July 31, 2002 order and the June 4, 2003 order on rehearing with
the U.S. Court of Appeals for the D.C. Circuit.

On
August 20, 2003, PJM issued a press release announcing the delay of Commonwealth Edison's integration in PJM which was previously planned for November 1, 2003. PJM
intends to review the events surrounding the August 14, 2003 blackout to ensure that the Joint Operating Agreement and associated reliability plan with the Midwest ISO will enhance the
reliability performance. As the investigation proceeds, PJM will determine a revised schedule for Commonwealth Edison's market integration in PJM. Such integration is not expected to take place during
2003.

On
July 23, 2003, the FERC issued an order finding that the regional through and out rates (RTORs) of the Midwest ISO and PJM are unjust and unreasonable when applied to
transactions sinking within the proposed Midwest ISO/PJM footprint and directed Midwest ISO and PJM to make a compliance filing within thirty days eliminating the RTORs. The FERC also initiated an
investigation and hearing to determine whether the through and out rate under the tariffs of individual former Alliance Companies are unjust, unreasonable or unduly discriminatory or preferential for
transactions sinking in the proposed Midwest ISO/PJM footprint. On October 14, 2003, the FERC issued an order extending the effective date for the elimination of Midwest ISO and PJM RTORs. The
new deadline for the
elimination of such rates will be set in the order on rehearing, which the FERC intends to issue in the near future.

On
September 29 and 30, 2003, the FERC held a hearing and inquiry into regional transmission organization issues related to the Midwest ISO and PJM. The purpose of the inquiry was
to gather sufficient information to move forward in resolving the commitment made by several entities, including Commonwealth Edison, to establish a joint and common market in the Midwest and PJM
region. The inquiry explored the impediments to the former Alliance Companies' participation in either the Midwest ISO or PJM. See also "Market Risk ExposuresCommodity Price
RiskAmericasIllinois Plants."

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Off-Balance Sheet Transactions

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

Environmental Matters and Regulations

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

Prior
to EME's purchase of the Homer City facilities, the United States Environmental Protection Agency, or EPA, requested information under Section 114 of the Clean Air Act from
the prior owners of the plant concerning physical changes at the plant. This request was part of the EPA's industry-wide investigation of compliance by coal-fired plants with
the Clean Air Act new source review, or NSR, requirements. On February 21, 2003, Midwest Generation received a request for information under Section 114 regarding past operations,
maintenance and physical changes at the Illinois coal plants from the EPA. On July 28, 2003, Commonwealth Edison received a substantially similar request for information from the EPA related to
these same plants. Other than these requests for information, no enforcement-related proceedings have been initiated by the EPA with respect to any of EME's United States facilities.

A
federal district court, ruling on a lawsuit filed by the EPA, found on August 7, 2003 that the Ohio Edison Company violated requirements of the NSR program within the Clean Air
Act by upgrading certain coal-fired power plants without first obtaining the necessary preconstruction permits. On August 26, 2003, another federal district court, ruling in an NSR
enforcement action against Duke Energy Corporation, adopted a different interpretation of the NSR provisions that could limit liability for similar upgrade projects.

In
addition, however, the EPA, on October 27, 2003, issued its final rule (effective December 26, 2003) revising its regulations to define more clearly a category of
activities that are not subject to NSR requirements under the "routine maintenance, repair and replacement" exclusion. This regulation may mitigate some or all of the potential impact of the Ohio
Edison decision, particularly as to future repair and replacement projects.

Both
recent judicial decisions and the newly issued regulation are currently under review by EME to assess what implications, if any, they will have on the operation of domestic power
plants owned or operated by EME or its subsidiaries, or on EME's results of operations or financial position.

Critical Accounting Policies and Estimates

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

New Accounting Standards

Adoption of New Accounting Pronouncements

Statement of Financial Accounting Standards No. 143.Effective January 1, 2003, EME adopted Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement
obligation

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

Statement of Financial Accounting Standards No. 149.In April 2003, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial
accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group
(DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into
or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in
fiscal quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The adoption of this standard had no impact on EME's consolidated financial
statements.

Statement of Financial Accounting Standards No. 150.Effective July 1, 2003, EME adopted Statement of Financial
Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards for how to classify
and measure certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability or
asset, as appropriate. At July 1, 2003, EME's company-obligated mandatorily redeemable securities and redeemable preferred stock were reclassified from the mezzanine equity section to the
liability section of EME's consolidated balance sheet. Dividend payments on these instruments are being recorded as interest expense commencing July 1, 2003 on EME's consolidated statements of
income. Prior period financial statements are not permitted to be restated for either of these changes. Therefore, there was no cumulative impact due to this accounting change incurred upon adoption.
See disclosures regarding these preferred securities in Note 8Preferred Securities.

Emerging Issues Task Force No. 01-08.In May 2003, the Emerging Issues Task Force (EITF) reached a
consensus on Issue No. 01-08, "Determining Whether an Arrangement Contains a Lease," which provides guidance on how to determine whether an arrangement contains a lease that is
within the scope of SFAS No. 13, "Accounting for Leases." A lease is defined as an agreement conveying the right to use property, plant, or equipment (land and/or depreciable assets), usually
for a stated period of time. The guidance issued by the EITF could affect the classification of a power sales agreement that meets specific criteria, such as a power sales agreement for substantially
all of the output from a power plant to one customer. If a power sales agreement meets the guidance
issued by the EITF, it would be accounted for as a lease subject to SFAS No. 13. The consensus is effective prospectively for EME arrangements entered into or modified after June 30,
2003. The consensus had no impact on EME's consolidated financial statements.

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

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adoption
of this standard had no impact on EME's financial statements. See disclosure regarding guarantees and indemnities in Note 9Commitments and Contingencies.

Accounting Pronouncements Issued But Not Yet Adopted

Other Statement of Financial Accounting Standards No. 133 Guidance.In June 2003, the Derivative Implementation
Group of the FASB under Statement No. 133 Implementation Issue Number C20 issued clarifying guidance related to pricing adjustments in contracts that qualify under the normal purchases and
normal sales exception under SFAS No. 133. This implementation guidance became effective on October 1, 2003. EME is currently re-evaluating which contracts, if any, that have
previously been designated as normal purchases or normal sales would now not qualify for this exception.

Emerging Issues Task Force No. 03-11.In July 2003, the EITF reached a consensus on Issue
No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging
Activities, and Not Held for Trading Purposes." EITF Issue No. 03-11 provides guidance on whether realized gains and losses on derivative contracts should be reported on a net or
gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and circumstances. In analyzing the facts and circumstances, EITF Issue
No. 99-19, "Reporting Revenue Gross as a Principal Versus Net as an Agent," should be considered. Gains and losses on non-trading derivative instruments are recognized
in net gains (losses) from price risk management and energy trading in the accompanying Consolidated Income Statements. The consensus is effective prospectively for EME transactions or arrangements
entered into or modified after September 30, 2003.

Statement of Financial Accounting Standards Interpretation No. 46.In January 2003, the FASB issued Statement
of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46). This interpretation of Accounting Research Bulletin No. 51, "Consolidated
Financial Statements," addresses consolidation by business enterprises of variable interest entities. The primary objective of the interpretation is to provide guidance on the identification of, and
financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as variable interest entities. This interpretation applies to variable
interest entities created after January 31, 2003, and applies to variable interest entities in which EME holds a variable interest that it acquired before February 1, 2003. Effective
October 9, 2003, the FASB issued Statement of Financial Accounting Standards Interpretation No. 46-6, "Effective Date of Financial Accounting Standards Interpretation
No. 46, Consolidation of Variable Interest Entities." This interpretation delays the effective date for applying the provisions of FIN 46 to variable interest entities in which EME holds a
variable interest that it acquired before February 1, 2003 until the end of the first interim or annual period ended after December 15, 2003.

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

EME
has concluded that it is the primary beneficiary of Brooklyn Navy Yard Cogeneration Partners L.P. since EME expects to absorb the majority of Brooklyn Navy Yard Cogeneration Partners
L.P.'s losses, if any, and expects to receive a majority of Brooklyn Navy Yard Cogeneration Partners L.P.'s residual returns, if any. Accordingly, EME will consolidate Brooklyn Navy Yard Cogeneration

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Partners
L.P. effective October 1, 2003. In accordance with the transition provisions of FIN 46, the consolidation of Brooklyn Navy Yard Cogeneration Partners L.P. will be based on the
historical cost of the assets, liabilities and non-controlling interest which would have been carried by EME effective when EME became the primary beneficiary. This means that EME will
consolidate the assets and liabilities of Brooklyn Navy Yard Cogeneration Partners L.P. using the October 1, 2003 balance sheet and eliminate intercompany balances. EME expects the
consolidation of this entity to increase total assets by approximately $364 million and total liabilities by approximately $440 million. Furthermore, EME expects to record a loss of
approximately $76 million in the fourth quarter of 2003 as a cumulative change of accounting as a result of consolidating this variable interest entity. This loss is primarily due to cumulative
losses allocated to the other 50% partner in excess of equity contributions recorded.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

EME's management, with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of EME's disclosure
controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the
end of the period covered by this report. Based on such evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, EME's disclosure controls
and procedures are effective.

Internal Control Over Financial Reporting

There have not been any changes in EME's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and
15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, EME's internal
control over financial reporting.

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PART IIOTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)   Exhibits

Exhibit No.

Description31.1

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

Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.32

Statement Pursuant to 18 U.S.C. Section 1350.99.1

Homer City Facilities Funds Flow From Operations for the twelve months ended September 30, 2003.99.2

Illinois Plants Funds Flow From Operations for the twelve months ended September 30, 2003.


(b)   Reports on Form 8-K

Date of Report

Date Filed

Item(s) ReportedAugust 5, 2003

August 5, 2003

12
*September 15, 2003

September 16, 2003

5


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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned
thereunto duly authorized.

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

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