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

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Form 10-Q

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

For the quarterly period ended March 31, 2002

or

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

For the transition period from  to

Commission file number 000-24890

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Edison Mission Energy(Exact name of registrant as specified in its charter)

Delaware(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

Number
of shares outstanding of the registrant's Common Stock as of May 8, 2002: 100 shares (all shares held by an affiliate of the registrant).

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TABLE OF CONTENTS

|Item                         |                                                                                       |  | Page
|---------------------------- | ------------------------------------------------------------------------------------- |  | ----
|PART IFinancial Information
|1.                           | Financial Statements                                                                  |  | 1   
|2.                           | Management's Discussion and Analysis of Results of Operations and Financial Condition |  | 18  
|3.                           | Quantitative and Qualitative Disclosures About Market Risk                            |  | 44  
|PART IIOther Information   
|1.                           | Legal Proceedings                                                                     |  | 45  
|6.                           | Exhibits and Reports on Form 8-K                                                      |  | 46  
|                             | Signatures                                                                            |  | 47  

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PART IFINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

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

|                                       |                                                                                       | Three Months Ended
March 31, |                             
|-------------------------------------- | ------------------------------------------------------------------------------------- | ---------------------------- | ----------------------------
|
|
|Operating Revenues                     |                                                                                       |                              |                             
|                                       | Electric revenues                                                                     |                              | $                           
|                                       | Equity in income from energy projects                                                 |                              |                             
|                                       | Equity in income from oil and gas investments                                         |                              |                             
|                                       | Net gains (losses) from energy trading and price risk management                      |                              |                             
|                                       | Operation and maintenance services                                                    |                              |                             
|                                       |                                                                                       |                              |                             
|                                       |                                                                                       |                              | Total operating revenues    
|                                       |                                                                                       |                              |                             
|Operating Expenses                     |                                                                                       |                              |                             
|                                       | Fuel                                                                                  |                              |                             
|                                       | Plant operations                                                                      |                              |                             
|                                       | Plant operating leases                                                                |                              |                             
|                                       | Operation and maintenance services                                                    |                              |                             
|                                       | Depreciation and amortization                                                         |                              |                             
|                                       | Long-term incentive compensation                                                      |                              |                             
|                                       | Administrative and general                                                            |                              |                             
|                                       |                                                                                       |                              |                             
|                                       |                                                                                       |                              | Total operating expenses    
|                                       |                                                                                       |                              |                             
|Operating income                       |                                                                                       |                              | 45,601                      
|                                       |                                                                                       |                              |                             
|Other Income (Expense)                 |                                                                                       |                              |                             
|                                       | Interest and other income                                                             |                              |                             
|                                       | Interest expense                                                                      |                              |                             
|                                       | Dividends on preferred securities                                                     |                              |                             
|                                       |                                                                                       |                              |                             
|                                       |                                                                                       |                              | Total other income (expense)
|                                       |                                                                                       |                              |                             
|                                       | Loss from continuing operations before income taxes and minority interest             |                              |                             
|                                       | Provision (benefit) for income taxes                                                  |                              |                             
|                                       | Minority interest                                                                     |                              |                             
|                                       |                                                                                       |                              |                             
|Loss From Continuing Operations        |                                                                                       |                              | (35,677                     
|                                       | Income (loss) from operations of discontinued foreign subsidiary, net of tax (Note 4) |                              |                             
|                                       |                                                                                       |                              |                             
|Income (Loss) Before Accounting Change |                                                                                       |                              | (35,839                     
|                                       | Cumulative effect of change in accounting, net of tax                                 |                              |                             
|                                       |                                                                                       |                              |                             
|Net Income (Loss)                      |                                                                                       | $                            | (35,839                     
|                                       |                                                                                       |                              |                             

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

1

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

|                                                  |                                                                         | Three Months Ended
March 31,                                                                                                                                           |        
|------------------------------------------------- | ----------------------------------------------------------------------- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------- | -------
|
|
|                                                  |                                                                         |                                                                                                                                                                        |        
|Net Income (Loss)                                 |                                                                         | $                                                                                                                                                                      | (35,839
|Other comprehensive income (expense), net of tax: |                                                                         |                                                                                                                                                                        |        
|                                                  | Foreign currency translation adjustments:                               |                                                                                                                                                                        |        
|                                                  |                                                                         | Foreign currency translation adjustments, net of income tax expense (benefit) of $867 and $(2,349) in 2002 and 2001, respectively                                      |        
|                                                  | Unrealized gains (losses) on derivatives qualified as cash flow hedges: |                                                                                                                                                                        |        
|                                                  |                                                                         | Cumulative effect of change in accounting for derivatives, net of income tax benefit of $110.9 million                                                                 |        
|                                                  |                                                                         | Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $11.5 million and $(17.4) million in 2002 and 2001, respectively |        
|                                                  |                                                                         | Reclassification adjustments included in net income (loss), net of income tax benefit of $0.4 million and $15.6 million in 2002 and 2001, respectively                 |        
|                                                  |                                                                         |                                                                                                                                                                        |        
|Other comprehensive income (expense)              |                                                                         |                                                                                                                                                                        | 54,650 
|                                                  |                                                                         |                                                                                                                                                                        |        
|Comprehensive Income (Loss)                       |                                                                         | $                                                                                                                                                                      | 18,811 
|                                                  |                                                                         |                                                                                                                                                                        |        

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

2

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

|                                  |                                                                                                   | March 31,
2002 |                                   | December 31,
2001
|--------------------------------- | ------------------------------------------------------------------------------------------------- | -------------- | --------------------------------- | -----------------
|
|Assets                            |                                                                                                   |                |                                   |                  
|Current Assets                    |                                                                                                   |                |                                   |                  
|                                  | Cash and cash equivalents                                                                         |                | $                                 | 368,586          
|                                  | Accounts receivabletrade, net of allowance of $12,942 and $14,603 in 2002 and 2001, respectively |                |                                   | 274,874          
|                                  | Accounts receivableaffiliates                                                                    |                |                                   | 233,092          
|                                  | Assets under energy trading and price risk management                                             |                |                                   | 177,206          
|                                  | Inventory                                                                                         |                |                                   | 180,041          
|                                  | Prepaid expenses and other                                                                        |                |                                   | 80,515           
|                                  |                                                                                                   |                |                                   |                  
|                                  |                                                                                                   |                | Total current assets              |                  
|                                  |                                                                                                   |                |                                   |                  
|Investments                       |                                                                                                   |                |                                   |                  
|                                  | Energy projects                                                                                   |                |                                   | 1,594,227        
|                                  | Oil and gas                                                                                       |                |                                   | 33,621           
|                                  |                                                                                                   |                |                                   |                  
|                                  |                                                                                                   |                | Total investments                 |                  
|                                  |                                                                                                   |                |                                   |                  
|Property, Plant and Equipment     |                                                                                                   |                | 7,138,169                         |                  
|                                  | Less accumulated depreciation and amortization                                                    |                |                                   | 756,028          
|                                  |                                                                                                   |                |                                   |                  
|                                  |                                                                                                   |                | Net property, plant and equipment |                  
|                                  |                                                                                                   |                |                                   |                  
|Other Assets                      |                                                                                                   |                |                                   |                  
|                                  | Long-term receivables                                                                             |                |                                   | 264,557          
|                                  | Goodwill                                                                                          |                |                                   | 647,750          
|                                  | Deferred financing costs                                                                          |                |                                   | 78,421           
|                                  | Long-term assets under energy trading and price risk management                                   |                |                                   | 12,368           
|                                  | Restricted cash and other                                                                         |                |                                   | 205,994          
|                                  |                                                                                                   |                |                                   |                  
|                                  |                                                                                                   |                | Total other assets                |                  
|                                  |                                                                                                   |                |                                   |                  
|Assets of Discontinued Operations |                                                                                                   |                | 78,654                            |                  
|                                  |                                                                                                   |                |                                   |                  
|Total Assets                      |                                                                                                   | $              | 10,612,047                        |                  
|                                  |                                                                                                   |                |                                   |                  

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

3

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

|                                                |                                                                                                   | March 31,
2002 |                                      | December 31,
2001 |  
|----------------------------------------------- | ------------------------------------------------------------------------------------------------- | -------------- | ------------------------------------ | ----------------- | -
|
|Liabilities and Shareholder's Equity            |                                                                                                   |                |                                      |                   |  
|Current Liabilities                             |                                                                                                   |                |                                      |                   |  
|                                                | Accounts payableaffiliates                                                                       |                | $                                    | 11,479            |  
|                                                | Accounts payable and accrued liabilities                                                          |                |                                      | 375,270           |  
|                                                | Liabilities under energy trading and price risk management                                        |                |                                      | 41,985            |  
|                                                | Interest payable                                                                                  |                |                                      | 85,735            |  
|                                                | Short-term obligations                                                                            |                |                                      | 95,269            |  
|                                                | Current portion of long-term incentive compensation                                               |                |                                      | 4,366             |  
|                                                | Current maturities of long-term obligations                                                       |                |                                      | 193,074           |  
|                                                |                                                                                                   |                |                                      |                   |  
|                                                |                                                                                                   |                | Total current liabilities            |                   |  
|                                                |                                                                                                   |                |                                      |                   |  
|Long-Term Obligations Net of Current Maturities |                                                                                                   |                | 5,765,366                            |                   |  
|                                                |                                                                                                   |                |                                      |                   |  
|Long-Term Deferred Liabilities                  |                                                                                                   |                |                                      |                   |  
|                                                | Deferred taxes and tax credits                                                                    |                |                                      | 912,023           |  
|                                                | Deferred revenue                                                                                  |                |                                      | 441,734           |  
|                                                | Long-term incentive compensation                                                                  |                |                                      | 36,712            |  
|                                                | Long-term liabilities under energy trading and price risk management                              |                |                                      | 149,233           |  
|                                                | Other                                                                                             |                |                                      | 245,147           |  
|                                                |                                                                                                   |                |                                      |                   |  
|                                                |                                                                                                   |                | Total long-term deferred liabilities |                   |  
|                                                |                                                                                                   |                |                                      |                   |  
|Liabilities of Discontinued Operations          |                                                                                                   |                | 37,253                               |                   |  
|                                                |                                                                                                   |                |                                      |                   |  
|Total Liabilities                               |                                                                                                   |                | 8,394,646                            |                   |  
|                                                |                                                                                                   |                |                                      |                   |  
|Minority Interest                               |                                                                                                   |                | 361,302                              |                   |  
|                                                |                                                                                                   |                |                                      |                   |  
|Preferred Securities of Subsidiaries            |                                                                                                   |                |                                      |                   |  
|                                                | Company-obligated mandatorily redeemable security of partnership holding solely parent debentures |                |                                      | 150,000           |  
|                                                | Subject to mandatory redemption                                                                   |                |                                      | 110,125           |  
|                                                |                                                                                                   |                |                                      |                   |  
|                                                | Total preferred securities of subsidiaries                                                        |                |                                      | 260,125           |  
|                                                |                                                                                                   |                |                                      |                   |  
|Commitments and Contingencies (Note 6)          |                                                                                                   |                |                                      |                   |  
|Shareholder's Equity                            |                                                                                                   |                |                                      |                   |  
|                                                | Common stock, no par value; 10,000 shares authorized; 100 shares issued and outstanding           |                |                                      | 64,130            |  
|                                                | Additional paid-in capital                                                                        |                |                                      | 2,631,917         |  
|                                                | Retained deficit                                                                                  |                |                                      | (852,902          | )
|                                                | Accumulated other comprehensive loss                                                              |                |                                      | (247,171          | )
|                                                |                                                                                                   |                |                                      |                   |  
|Total Shareholder's Equity                      |                                                                                                   |                | 1,595,974                            |                   |  
|                                                |                                                                                                   |                |                                      |                   |  
|Total Liabilities and Shareholder's Equity      |                                                                                                   | $              | 10,612,047                           |                   | $
|                                                |                                                                                                   |                |                                      |                   |  

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

4

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

|                                                                        |                                                                                       | Three Months Ended
March 31,                             |                                                    
|----------------------------------------------------------------------- | ------------------------------------------------------------------------------------- | -------------------------------------------------------- | ---------------------------------------------------
|
|
|Cash Flows From Operating Activities                                    |                                                                                       |                                                          |                                                    
|                                                                        | Loss from continuing operations, after accounting change, net                         |                                                          | $                                                  
|                                                                        | Adjustments to reconcile loss to net cash provided by (used in) operating activities: |                                                          |                                                    
|                                                                        |                                                                                       | Equity in income from energy projects                    |                                                    
|                                                                        |                                                                                       | Equity in income from oil and gas investments            |                                                    
|                                                                        |                                                                                       | Distributions from energy projects                       |                                                    
|                                                                        |                                                                                       | Dividends from oil and gas                               |                                                    
|                                                                        |                                                                                       | Depreciation and amortization                            |                                                    
|                                                                        |                                                                                       | Amortization of discount on short-term obligations       |                                                    
|                                                                        |                                                                                       | Deferred taxes and tax credits                           |                                                    
|                                                                        |                                                                                       | Cumulative effect of change in accounting, net of tax    |                                                    
|                                                                        | Changes in operating assets and liabilities:                                          |                                                          |                                                    
|                                                                        |                                                                                       | Decrease in accounts receivable                          |                                                    
|                                                                        |                                                                                       | Increase in inventory                                    |                                                    
|                                                                        |                                                                                       | Decrease in prepaid expenses and other                   |                                                    
|                                                                        |                                                                                       | Decrease in accounts payable and accrued liabilities     |                                                    
|                                                                        |                                                                                       | Increase (decrease) in interest payable                  |                                                    
|                                                                        |                                                                                       | Increase (decrease) in long-term incentive compensation  |                                                    
|                                                                        |                                                                                       | Decrease (increase) in assets under risk management, net |                                                    
|                                                                        | Other operating, net                                                                  |                                                          |                                                    
|                                                                        |                                                                                       |                                                          |                                                    
|                                                                        |                                                                                       |                                                          | 18,468                                             
|                                                                        | Operating cash flow from discontinued operations                                      |                                                          |                                                    
|                                                                        |                                                                                       |                                                          |                                                    
|                                                                        |                                                                                       |                                                          | Net cash provided by (used in) operating activities
|                                                                        |                                                                                       |                                                          |                                                    
|Cash Flows From Financing Activities                                    |                                                                                       |                                                          |                                                    
|                                                                        | Borrowing on long-term obligations                                                    |                                                          |                                                    
|                                                                        | Payments on long-term obligations                                                     |                                                          |                                                    
|                                                                        | Short-term financing, net                                                             |                                                          |                                                    
|                                                                        | Cash dividends to parent                                                              |                                                          |                                                    
|                                                                        | Funds provided to discontinued operations                                             |                                                          |                                                    
|                                                                        |                                                                                       |                                                          |                                                    
|                                                                        |                                                                                       |                                                          | (30,541                                            
|                                                                        | Financing cash flow from discontinued operations                                      |                                                          |                                                    
|                                                                        |                                                                                       |                                                          |                                                    
|                                                                        |                                                                                       |                                                          | Net cash 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                                                           |                                                          |                                                    
|                                                                        | Other, net                                                                            |                                                          |                                                    
|                                                                        |                                                                                       |                                                          |                                                    
|                                                                        |                                                                                       |                                                          | (1,147                                             
|                                                                        | Investing cash flow from discontinued operations                                      |                                                          |                                                    
|                                                                        |                                                                                       |                                                          |                                                    
|                                                                        |                                                                                       |                                                          | Net cash used in investing activities              
|                                                                        |                                                                                       |                                                          |                                                    
|Effect of exchange rate changes on cash                                 |                                                                                       |                                                          | 2,885                                              
|                                                                        |                                                                                       |                                                          |                                                    
|Net decrease in cash and cash equivalents                               |                                                                                       |                                                          | (17,537                                            
|Cash and cash equivalents at beginning of period                        |                                                                                       |                                                          | 434,249                                            
|                                                                        |                                                                                       |                                                          |                                                    
|Cash and cash equivalents at end of period                              |                                                                                       |                                                          | 416,712                                            
|Cash and cash equivalents classified as part of discontinued operations |                                                                                       |                                                          | (48,126                                            
|                                                                        |                                                                                       |                                                          |                                                    
|Cash and cash equivalents of continuing operations                      |                                                                                       | $                                                        | 368,586                                            
|                                                                        |                                                                                       |                                                          |                                                    

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

5

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EDISON MISSION ENERGY AND SUBSIDIARIES        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        MARCH 31, 2002

NOTE 1.    GENERAL

All adjustments, including recurring accruals, have been made that are necessary to present fairly the consolidated financial position and results of operations
for the periods covered by this report. The results of operations for the three months ended March 31, 2002 are not necessarily indicative of the operating results for the full year.

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

Certain
prior period amounts have been reclassified to conform to the current period financial statement presentation.

NOTE 2.    INVENTORY

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

March 31,
2002

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

$
120.9

$
110.1Spare parts, materials and supplies


59.1


57.3Total

$
180.0

$
167.4


NOTE 3.    ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

|                                      |  | Currency
Translation
Adjustments |        | Unrealized Gains
(Losses) on Cash
Flow Hedges |   | Accumulated Other
Comprehensive
Income (Loss) |  
|------------------------------------- |  | -------------------------------- | ------ | --------------------------------------------- | - | --------------------------------------------- | -
|Balance at December 31, 2001          |  | $                                | (133.4 | )                                             | $ | (168.4                                        | )
|Current period change                 |  |                                  | 15.8   |                                               |   | 38.8                                          |  
|                                      |  |                                  |        |                                               |   |                                               |  
|Balance at March 31, 2002 (Unaudited) |  | $                                | (117.6 | )                                             | $ | (129.6                                        | )
|                                      |  |                                  |        |                                               |   |                                               |  

Unrealized
gains (losses) on cash flow hedges included the hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project in
Australia. This contract could not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. Approximately 62% of our
accumulated other comprehensive loss at March 31, 2002 related to unrealized losses on the cash flow hedge resulting from this contract. These losses arise from current forecasts of future
electricity prices in these markets being greater than our contract prices. Although the contract prices are below the current market prices, we believe that these contract prices meet our profit
objectives and insulate us

6

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from fluctuations in market prices. Assuming the long-term contract with the State Electricity Commission of Victoria continues to qualify as a cash flow hedge, future changes in the
forecast of market prices for contract volumes included in this agreement will cause increases or decreases in our other comprehensive income without significantly affecting our net income. In
addition to this contract, unrealized gains (losses) on cash flow hedges included our share of interest rate swaps of our unconsolidated affiliates and the Loy Yang B project.

As
our hedged positions are realized, approximately $0.4 million, after tax, of the net unrealized losses on cash flow hedges will be reclassified into earnings during the next
twelve months. Management expects that these net unrealized losses will be offset when the hedged items are recognized in earnings. The maximum period over which a cash flow hedge is designated,
excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is 15 years.

NOTE 4.    DISCONTINUED OPERATIONS

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

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

Summarized
results of discontinued operations are as follows:

Three Months Ended
March 31,2002

2001(Unaudited)(in millions)Total operating revenues

$
0.6

$
183.8Income (loss) before income taxes


(0.2
)

11.6Income (loss) before accounting change


(0.2
)

13.2Cumulative effect of change in accounting, net of income tax expense of $2.5 million for 2001





5.8Income (loss) from operations of discontinued foreign subsidiary


(0.2
)

19.0


7

---

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

March 31,
2002

December 31,
2001(Unaudited)Cash and cash equivalents

$
48.1

$
62.1Accounts receivabletrade, net of allowance of $1.8 million and $1.4 million in 2002 and 2001, respectively


29.8


88.4Other current assets


0.7


1.5Total current assets


78.6


152.0Other assets





1.6Total long-term assets





1.6Assets of discontinued operations

$
78.6

$
153.6Accounts payable and accrued liabilities

$
35.8

$
51.6Interest payable


1.4


4.2Total current liabilities


37.2


55.8Liabilities of discontinued operations

$
37.2

$
55.8


NOTE 5.    RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

Non-Trading Derivative Financial Instruments

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

March 31,
2002

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

$
(21.9
)
$
(35.8
)Interest rate options


0.3


(1.0
)Commodity price:Forwards


49.2


63.8Futures


(7.0
)

(8.4
)Options





0.4Swaps


(119.9
)

(137.6
)Foreign currency forward exchange agreements


(0.5
)

(0.6
)Cross currency interest rate swaps


16.8


27.6


In
assessing the fair value of our non-trading derivative financial instruments, we use a variety of methods and assumptions based on the market conditions and associated
risks existing at each balance

8

---

sheet date. The fair value of commodity price contracts takes in account quoted marked prices, time value of money, volatility of the underlying commodities and other factors.

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

Energy Trading

On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our operations beyond the
traditional marketing of our electric power to include trading of electricity and fuels. In conducting our trading activities, we seek to generate profit from price volatility of electricity and fuels
by buying and selling these commodities in wholesale markets. We generally balance forward sales and purchases contracts and manage our exposure through a value at risk analysis as described further
below. We also conduct price risk management activities with third parties not related to our power plants or investments in energy projects, including the restructuring of power sales and power
supply agreements.

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

March 31, 2002

December 31, 2001Assets

Liabilities

Assets

Liabilities(Unaudited)Forward contracts

$
98.3

$
4.8

$
4.6

$
2.9Futures contracts








0.1


0.1Option contracts


0.5


0.2





Swap agreements


10.4


10.5


0.2


Total

$
109.2

$
15.5

$
4.9

$
3.0


Quoted
market prices are used to determine the fair value of the financial instruments related to trading activities, except for the power sales agreement with an unaffiliated electric
utility that we purchased and restructured and a long-term power supply agreement with another unaffiliated party. We recorded these agreements at fair value based upon a discounting of
future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of the power supply
agreement.

9

---

NOTE 6.    COMMITMENTS AND CONTINGENCIES

Commercial Commitments

The following table summarizes our consolidated commercial commitments as of March 31, 2002. Details regarding these commercial commitments are discussed
in the sections following the table.

|                                                       |  | Amount of Commitments Per Period in U.S.$ |       | 
|------------------------------------------------------ |  | ----------------------------------------- | ----- | 
|
|
|
|Standby letters of credit                              |  | $                                         | 37.7  | 
|Firm commitment for asset purchase                     |  |                                           | 3.3   | 
|Firm commitments to contribute project equity          |  |                                           | 67.8  | 
|Environmental improvements at our project subsidiaries |  |                                           | 38.6  | 
|                                                       |  |                                           |       | 
|Total Commercial Commitments                           |  | $                                         | 147.4 | 
|                                                       |  |                                           |       | 

Credit Support for Trading and Price Risk Management Activities

Our domestic trading and price risk management activities are conducted through our subsidiary, Edison Mission Marketing & Trading, Inc. As part of
obtaining an investment grade rating for this subsidiary, we have entered into a support agreement, which commits us to contribute up to $300 million in equity to Edison Mission
Marketing & Trading, if needed, to meet cash requirements. An investment grade rating is an important benchmark used by third parties when deciding whether or not to enter into master contracts
and trades with Edison Mission Marketing & Trading. The majority of Edison Mission Marketing & Trading's contracts have various standards of creditworthiness, including the maintenance
of specified credit ratings. Currently we provide a parent company guaranty by Edison Mission Energy to support Edison Mission Marketing & Trading's contracts. If we do not maintain an
investment grade rating or if other events adversely affect our financial position, a third party could request us to provide adequate assurance. Adequate assurance could take the form of supplying
additional financial information, collateral, letters of credit or cash. Failure to provide adequate assurance could result in a counterparty liquidating an open position and filing a claim against us
for any losses.

Our
trading and price risk management activity has been adversely affected by a number of factors, including the bankruptcy filing of Enron, increased concern regarding the liquidity of
independent power companies, decrease in market prices in U.S. wholesale energy markets, and risk factors related to our business, which have limited our trading and price risk management activities.
It is not certain that market conditions or risks related to our business will change to allow us to be able to conduct trading and price risk management activities in a manner favorable to us.

10

---

Firm Commitment for Asset Purchase

Project

Local Currency

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

7 billion Italian Lira

$
3.3


---

Firm Commitments to Contribute Project Equity

Project

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

$
45.3Sunrise(ii)

$
86.8


---

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

11

---

Contingencies

Paiton

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

PT
PLN and Paiton Energy signed a Binding Term Sheet on December 14, 2001 setting forth the commercial terms under which Paiton Energy is to be paid for capacity and energy
charges, as well as a monthly "restructure settlement payment" covering arrears owed by PT PLN ($456 million at
December 31, 2001) and the settlement of other claims. In addition, the Binding Term Sheet provides for an extension of the terms of the power purchase agreement from 2029 to 2040. Paiton
Energy and PT PLN are continuing negotiations on an amendment to the power purchase agreement that will include the agreed commercial terms in the Binding Term Sheet, with the aim of concluding those
negotiations by June 30, 2002. The Binding Term Sheet serves as the basis under which PT PLN will pay Paiton Energy beginning January 1, 2002. The Binding Term Sheet will expire on
June 30, 2002 unless extended by mutual agreement. Previously, PT PLN and Paiton Energy entered into a Phase I Agreement (covering January 1 to June 30, 2001), a Phase II
Agreement (covering July 1 to September 30, 2001) and a Phase III Agreement (covering October 1 to December 31, 2001). PT PLN has made all payments to Paiton Energy as
required under these agreements, which are superseded by the Binding Term Sheet. Paiton Energy is continuing to generate electricity to meet the power demand in the region. PT PLN has paid invoices
for the months of January and February 2002, as well as the restructure settlement payments due for those months. Paiton Energy believes that PT PLN will continue to make payments for
electricity under the Binding Term Sheet while negotiations on the amendment to the power purchase agreement continue. Although completion of negotiations may be delayed beyond June 30, 2002,
Paiton Energy continues to believe that negotiations on the long-term restructuring of the tariff will be successful.

Our
investment in the Paiton project increased to $510.9 million at March 31, 2002 from $492.1 million at December 31, 2001. The increase in the investment
account resulted from our subsidiary recording its proportionate share of net income from Paiton Energy as well as its proportionate share of other comprehensive income. Our investment in the Paiton
project will increase (decrease) from earnings (losses) from Paiton Energy and decrease by cash distributions. Assuming Paiton Energy remains profitable, we expect the investment account will increase
during the next several years as earnings are expected to exceed cash distributions.

Under
the Binding Term Sheet, past due accounts receivable due under the original power purchase agreement are to be compensated through a restructure settlement payment in the amount of
US$4 million per month for a period of 30 years. If the power purchase agreement amendment is not completed within reasonable time frames acceptable to Paiton Energy, the parties would
be entitled to revert back to the terms and conditions of the original power purchase agreement in order to pursue arbitration in the international courts.

12

---

Paiton
Energy and PT PLN are currently negotiating an amendment to the power purchase agreement which will incorporate the terms and conditions of the Binding Term Sheet into the power
purchase agreement. Entering into this agreement has been approved by the project lenders. Paiton Energy and its lenders have initiated negotiations on a restructuring of the senior debt which takes
into account the revised payment terms contained in the Binding Term Sheet. The outcome of these negotiations is uncertain at the present time. However, we believe that we will ultimately recover our
investment in the project.

Brooklyn Navy Yard

Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. Our wholly-owned subsidiary owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of
$136.8 million. Brooklyn Navy Yard Cogeneration Partners has asserted general monetary claims against the contractor. In connection with a $407 million non-recourse project
refinancing in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner from all claims and costs arising from or in connection with the contractor litigation, which
indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. Additional amounts, if any, which would be due to the contractor with respect to completion of construction of the
power plant would be accounted for as an addition to the power plant investment. Furthermore, our partner has executed a reimbursement agreement with us that provides recovery of up to
$10 million over an initial amount, including legal fees, payable from its management and royalty fees. We believe that the outcome of this litigation will not have a material adverse effect on
our consolidated financial position or results of operations. We are currently offering our interest in the Brooklyn Navy Yard project for sale.

ISAB

In connection with the financing of the ISAB project, we have guaranteed for the benefit of the banks financing the construction of the ISAB project our
subsidiary's obligation to contribute project equity and subordinated debt totaling up to approximately $39 million. The amount of payment under the obligation is contingent upon the outcome of
an arbitration proceeding brought in 1999 by the contractor of the project against ISAB Energy. On April 19, 2002, the arbitration tribunal issued a partial award on liability dismissing 11 of
the contractor's 15 original claims. The tribunal found there was a legal and factual basis for a "slight extension" of the guaranteed completion date and a "slight indemnification" of the contractor
in relation to two other relatively minor claims. Certain additional claims are still to be heard by the tribunal on a date to be agreed by the parties or as otherwise directed by the tribunal.

Regulatory Developments Affecting Sunrise Power Company

Sunrise Power Company, in which we own a 50% interest, sells all of its output to the California Department of Water Resources under a power purchase agreement
entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the Federal Energy
Regulatory Commission against all sellers of long-term

13

---

contracts to the California Department of Water Resources, including Sunrise Power Company. The California Public Utilities Commission complaint alleged that the contracts are "unjust and
unreasonable" on price and other terms, and requests that the contracts be abrogated. The California Electricity Oversight Board complaint made a similar allegation and requested that the contracts be
deemed voidable at the request of the California Department of Water Resources or, in the alternative, abrogated as of a future date, to allow for the possibility of renegotiation. Sunrise filed a
motion to dismiss with the Federal Energy Regulatory Commission requesting, among other things, a dismissal of both complaints and expedited treatment of its motion, and both the California Public
Utilities Commission and the California Electricity Oversight Board have filed responses to the motions of Sunrise and other defendants. On April 25, 2002, the Federal Energy Regulatory
Commission denied Sunrise's motion to dismiss the complaints and set hearings on the contracts executed prior to June 20, 2001, but was silent as to what, if any, actions it intended to take
with respect to contracts, including the Sunrise contract, executed after that date. Sunrise has filed a motion seeking confirmation from the Federal Energy Regulatory Commission that it does not
intend to review contracts executed after June 20, 2001 or, in the alternative, requesting a rehearing regarding the denial of its motion to dismiss.

On
May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Los Angeles Superior Court 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 of the contracts entered into in 2001, as well as all of the
contracts renegotiated in 2002, as a result of a purported conflict of interest by Mr. Budhraja. Sunrise Power Company has not yet been served with a copy of the complaint.

Indemnities



Some of our subsidiaries have entered into indemnification agreements, under which the subsidiaries agreed to repay capacity payments to the projects' power
purchasers in the event the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. Obligations under these
indemnification agreements as of March 31, 2002, if payment were required, would be $226.2 million. We have no reason to believe that the projects will either terminate their performance
or reduce their electric power producing capability during the term of the power contracts.



In support of the business of our subsidiaries, we have, from time to time, entered into guarantees and indemnity agreements with respect to our subsidiaries'
obligations such as debt service, fuel supply or
the delivery of power, and have also entered into reimbursement agreements with respect to letters of credit issued to third parties to support our subsidiaries' obligations. We have also, from time
to time, entered into guarantees and indemnification agreements with respect to acquisitions made by our subsidiaries. In this regard, we have indemnified the previous owners of the Illinois Plants,
the Homer

14

---

City facilities and the EcoEléctrica facilities for specified liabilities, including environmental liabilities, incurred as a result of their prior ownership of the plants. We do not
believe these indemnification obligations will have a material impact on us.



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

Additional Gas-Fired Generation

Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, our subsidiary committed to install one or more
gas-fired electric generating units having an additional gross dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago. The acquisition documents require
that commercial operation of this project commence by December 15, 2003. Due to additional capacity for new gas-fired generation in the Mid-America Interconnected
Network (generally referred to as MAIN) region and the improved reliability of power generation in the Chicago area, we have undertaken preliminary discussions with Exelon Generation regarding
alternatives to construction of 500 MW of capacity which we do not believe is needed at this time. If we were to install this additional capacity, we estimate that the cost could be as much as
$320 million.

Contingent Obligations to Contribute Project Equity

Project

Local Currency

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



$
5.3ISAB (ii)

86 billion Italian Lira

$
38.6


---



15

---



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

Environmental

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

NOTE 7.    BUSINESS SEGMENTS

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

|Three Months Ended      |  | Americas |         | Asia Pacific |   | Europe and
Middle
East |  | Corporate/
Other |         | Total
|----------------------- |  | -------- | ------- | ------------ | - | ---------------------- |  | ---------------- | ------- | -----
|
|March 31, 2002          |  |          |         |              |   |                        |  |                  |         |      
|Operating revenues      |  | $        | 303.4   |              | $ | 154.2                  |  | $                | 152.1   |      
|Operating income (loss) |  |          | (19.5   | )            |   | 54.7                   |  |                  | 51.4    |      
|Total assets            |  | $        | 4,783.1 |              | $ | 3,209.2                |  | $                | 2,024.0 |      
|March 31, 2001          |  |          |         |              |   |                        |  |                  |         |      
|Operating revenues      |  | $        | 408.7   |              | $ | 48.8                   |  | $                | 127.9   |      
|Operating income (loss) |  |          | 74.8    |              |   | 25.6                   |  |                  | 41.4    |      
|Total assets            |  | $        | 6,605.7 |              | $ | 2,159.3                |  | $                | 4,859.0 |      

16

---

NOTE 8.    INVESTMENTS

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

Three Months Ended
March 31,2002

2001(Unaudited)
(in millions)Operating revenues

$
108.3

$
376.2Operating income


5.5


79.9Net income


8.4


79.9


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

Three Months Ended
March 31,2002

2001(Unaudited)
(in millions)Operating revenues

$
56.7

$
112.2Operating income


27.5


86.7Net income


17.5


56.8


17

---

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

The following discussion contains forward-looking statements. These statements are based on our current plans and expectations and involve
risks and uncertainties which could cause actual future activities and results of operations to be materially different from those set forth in the forward-looking statements. Unless otherwise
indicated, the information presented in this section is with respect to Edison Mission Energy and our consolidated subsidiaries.

The Management's Discussion and Analysis of Results of Operations and Financial Condition of this Form 10-Q should be read along with the
Management's Discussion and Analysis of Results of Operations and Financial Condition included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended
December 31, 2001. This Management's Discussion and Analysis of Results of Operations and Financial Condition refers to specified portions of Edison Mission Energy's Management's Discussion and
Analysis of Results of Operations and Financial Condition for the year ended December 31, 2001.

General

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

As
of March 31, 2002, we owned interests in 28 domestic and 49 international operating power projects with an aggregate generating capacity of 23,605 MW, of which our share was
18,854 MW. At that date, one domestic and six international projects, totaling 985 MW of generating capacity, of which our anticipated share will be approximately 584 MW, were under construction. At
March 31, 2002, we had consolidated assets of $10.6 billion and total shareholder's equity of $1.6 billion.

Disposition of Investments in Energy Projects

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

We
are currently offering for sale our interests in the Brooklyn Navy Yard, EcoEléctrica, and Gordonsville projects. A number of independent power producers have announced
plans to sell assets which, together with general market conditions affecting independent power producers during the past year, have adversely affected the market value of power plants. Management has
not made a decision to sell these projects.

18

---

RESULTS OF OPERATIONS

Operating revenues are derived from our majority-owned domestic and international entities. Equity in income from investments relates to energy projects where our
ownership interest is 50% or less in the projects. The equity method of accounting is generally used to account for the operating results of entities over which we have a significant influence but in
which we do not have a controlling interest. With respect to entities accounted for under the equity method, we recognize our proportional share of the income or loss of such entities.

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

Three Months Ended March 31,2002

2001Projects

Business
SegmentAmount

%(1)

Amount

%(1)(Unaudited)Operating revenues:Illinois Plants

Americas

$
163.8

27

$
175.8

30Homer City facilities

Americas


85.5

14


128.5

22Big 4 projects(2)

Americas


6.5

1


40.2

7First Hydro

Europe


83.7

14


68.2

12Four Star(3)

Americas


7.5

1


38.2

7Operating income:Illinois Plants

Americas

$
(57.9
)


$
(66.8
)Homer City facilities

Americas


2.4




54.8Big 4 projects(2)

Americas


6.5




40.2First Hydro

Europe


23.8




26.7Four Star(3)

Americas


7.2




37.8


---

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

19

---

Americas

Three Months Ended
March 31,2002

2001(Unaudited)
(in millions)Operating revenues

$
258.9

$
307.5Net gains from energy trading and price risk management


18.2


18.9Equity in income from investments


26.3


82.3Total operating revenues


303.4


408.7Fuel and plant operations (including plant operating leases)


282.5


288.7Depreciation and amortization


34.2


39.4Administrative and general


6.2


5.8Operating income (loss)

$
(19.5
)
$
74.8


Operating Revenues

Operating revenues decreased $48.6 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 decrease primarily resulted from
lower electric revenues from the Homer City facilities due to decreased generation and lower energy prices. On February 10, 2002, we experienced a major unplanned outage due to damage to the
selective catalytic reduction system of one of the units at the Homer City facilities, known as Unit 3. The unit was restored to operation on April 4, 2002 and is operating with the selective
catalytic reduction system bypassed. Reconnection of the selective catalytic reduction system will be implemented at a later date in accordance with an outage plan to be developed.

Electric
power generated at the Illinois Plants is sold under power purchase agreements with Exelon Generation Company. Exelon Generation is obligated to make capacity payments for the
plants under contract and an energy payment for electricity produced by these plants. Our revenues under these power purchase agreements were $161 million and $165 million for the
three-month periods ended March 31, 2002 and 2001, respectively. This represented 26% and 28% of our consolidated operating revenues in 2002 and 2001, respectively. For more information on
these power purchase agreements, see "Market Risk ExposuresIllinois Plants."

Net
gains (losses) from energy trading activities were $16.5 million and $(4.1) million for the first quarter of 2002 and 2001, respectively. During the first quarter of 2002, we
completed the restructuring of a power sales agreement with an unaffiliated electric utility. As part of the transaction, we purchased the power sales agreement held by a third party, modified its
terms and conditions, and entered into a long-term year power supply agreement with another party. Although the sale and purchase of power arising from these contracts will occur over
their term, we have recorded during the first quarter of 2002 net gains of $15.3 million attributable to their fair value at inception in accordance with EITF 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities" (generally referred to as mark to market accounting). See "Liquidity and Capital ResourcesSubsidiary
Financing Plans" for a discussion of the non-recourse debt incurred to finance the purchase of the power sales agreement. The net losses from energy trading activities during the first
quarter of 2001 were due to a decrease in West Coast energy prices reducing the fair market value of the related contracts.

Net
gains (losses) from price risk management activities recorded at fair value under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS No. 133), were $1.7 million and $23 million for the first quarter of 2002 and 2001,

20

---

respectively. The gains in 2001 were primarily due to realized and unrealized gains for a gas swap purchased to hedge a portion of our gas price risk related to our share of gas production in Four
Star, an oil and gas company in which we have a minority interest and which we account for under the equity method. During the first quarter of 2001, we recorded a gain on these gas swaps of
$17.4 million due to a decrease in gas prices. We have not entered into hedge transactions related to the gas price risk of our investment in Four Star for 2002 or beyond. In addition, during
the first quarter of 2001, we recorded a gain of $5.5 million resulting from the change in market value of future contracts entered into with respect to a portion of our anticipated fuel
purchases through 2002 at the Illinois Plants that did not qualify for hedge accounting under SFAS No. 133.

Equity
in income from investments decreased $56 million during the first quarter of 2002, compared to the same prior year period. The 2002 decrease was primarily the result of
lower earnings from cogeneration projects due to lower energy pricing and lower revenues from oil and gas investments due to lower gas prices.

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

Operating Expenses

Fuel and plant operations, including plant operating leases, decreased $6.2 million for the first quarter of 2002, compared to the first quarter of 2001.
The 2002 decrease in fuel expense of $27.7 million resulted from lower fuel costs at the Homer City facilities due to decreased generation during the first quarter of 2002, as compared to the
first quarter of 2001, when the facilities experienced the major unplanned outage at Unit 3. In addition, fuel costs were lower at the Illinois Plants during the first quarter of 2002 due to lower
fuel costs at the Collins Station as compared to the first quarter of 2001.

Partially
offsetting the 2002 decrease in fuel expense was an increase in plant operating leases of $16.6 million during the first quarter of 2002, as compared to the first
quarter of 2001, resulting primarily from lease costs related to the sale-leaseback commitments for the Homer City facilities. There were no comparable lease costs for the Homer City
facilities during the first quarter of 2001.

Depreciation
and amortization expense decreased $5.2 million for the first quarter of 2002, compared to the same prior year period. The 2002 decrease resulted from lower
depreciation expense at the Homer City facilities related to the sale-leaseback transaction for the Homer City facilities to third-party lessors in December 2001.

Administrative
and general expenses consist of administrative and general expenses incurred at our trading operations in Boston, Massachusetts. There were no material changes in the
first quarter 2002 administrative and general expenses from the first quarter of 2001.

Operating Income

Operating loss totaled $19.5 million during the first quarter of 2002, compared to operating income of $74.8 million during the first quarter of
2001. The 2002 decrease was primarily due to lower operating income of $52.4 million from the Homer City facilities resulting from the major unplanned outage at Unit 3, lower equity in income
from investments in energy projects and lower equity in income from oil and gas investments discussed above.

We
believe that the costs to repair the damage to Unit 3 at Homer City should be covered by insurance and by contractual obligations of the contractor who installed the selective
catalytic reduction

21

---

system. We have completed a preliminary investigation of the event; however, a more in-depth analysis of the root causes of the event will be required to determine the extent to which
insurers and/or the contractor will cover the resulting costs of property damage and repair.

Asia-Pacific

Three Months Ended
March 31,2002

2001(Unaudited)
(in millions)Operating revenues

$
141.0

$
46.2Net losses from energy trading and price risk management


(1.1
)

(0.5
)Equity in income from investments


14.3


3.1Total operating revenues


154.2


48.8Fuel and plant operations


85.3


15.0Depreciation and amortization


14.2


8.2Operating income

$
54.7

$
25.6


Operating Revenues

Operating revenues increased $94.8 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was primarily due to
consolidating Contact Energy operating revenues as a result of our increase in ownership to 51.2% majority-control in the company, effective June 1, 2001.

Net
losses from price risk management activities recorded at fair value were $1.1 million and $0.5 million for the first quarter of 2002 and 2001, respectively. The losses
primarily represent the ineffective portion of a long-term contract with the State Electricity Commission of Victoria entered into by the Loy Yang B plant, which is a derivative that
qualified as a cash flow hedge under SFAS No. 133. See "Note 3. Accumulated Other Comprehensive Income (Loss)," for further discussion.

Equity
in income from investments increased $11.2 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase is primarily due to an increase
in our share of income from the Paiton project of $13.5 million. Beginning January 1, 2002, Paiton Energy recorded revenue in accordance with the Binding Term Sheet, which is described
in more detail under "Note 6. Commitments and ContingenciesContingenciesPaiton." Revenue recognized under the Binding Term Sheet is comprised of capacity
payments (based on the availability of the power plant) and energy payments (based on electricity generated). Recognition of revenue on the basis of the Binding Term Sheet resulted in a net profit by
Paiton Energy for the three months ended March 31, 2002. Prior to the execution of the Binding Term Sheet, we assumed the lower end of a range of expected outcomes of negotiations of a revised
power purchase agreement, which resulted in no recognition of income during the three months ended March 31, 2001. Partially offsetting this increase in 2002 was a decrease in earnings from
Contact Energy reflecting Contact Energy being accounted for on a consolidated basis effective June 1, 2001, compared to the equity method of accounting utilized by us prior to our acquisition
of a controlling interest in the company.

Operating Expenses

Fuel and plant operations increased $70.3 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was primarily due
to the consolidation of Contact Energy operating expenses, effective June 1, 2001.

22

---

Depreciation
and amortization expense increased $6 million for the first quarter of 2002, compared to the first quarter of 2001. The increase primarily reflects the consolidation
of Contact Energy depreciation and amortization expenses, effective June 1, 2001.

Operating Income

Operating income increased $29.1 million during the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was primarily due to
consolidation of Contact Energy's results of operations, effective June 1, 2001, and higher equity in income from investments discussed above.

Europe and Middle East(1)

Three Months Ended
March 31,2002

2001(Unaudited)
(in millions)Operating revenues

$
135.8

$
130.6Net gains (losses) from energy trading and price risk management


4.3


(1.9
)Equity in income (loss) from investments


12.0


(0.8
)Total operating revenues


152.1


127.9Fuel and plant operations


91.5


75.6Depreciation and amortization


9.2


10.9Operating income

$
51.4

$
41.4


---

Operating Revenues

Operating revenues increased $5.2 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase resulted primarily from
higher electric revenues from the First Hydro plant due to favorable ancillary services revenues, increased generation and sales of purchased power during the first quarter of 2002, compared to the
same prior year period. On March 27, 2001, the United Kingdom pool pricing system was replaced with a bilateral physical trading system referred to as the new electricity trading arrangements,
generally referred to as NETA. The new electricity trading arrangements are described in further detail under "Market Risk ExposuresUnited Kingdom." As a result of the
bilateral market under the new electricity trading arrangements, First Hydro has entered in greater volumes of power purchase and power sale contracts to optimize the timing of generation from First
Hydro pump storage plants. The First Hydro plant and the Iberian Hy-Power plant are expected to provide for higher electric revenues during the winter months.

Net
gains (losses) from price risk management activities recorded at fair value were $4.3 million and ($1.9) million for the first quarter of 2002 and 2001, respectively. The 2002
gains primarily represent the change in market value of long-term commodity contracts entered into by the First Hydro plant for the purchase and sale of electricity that were recorded at
fair value under SFAS No. 133 with changes in fair value recorded through the income statement, effective July 1, 2001.

Equity
in income from investments increased $12.8 million during the first quarter of 2002, compared to the same prior year period. The 2002 increase was due to higher
profitability of our

23

---

interest in the ISAB project resulting from increased generation and settlement of an insurance claim. During the first quarter of 2001, we recorded losses from this project.

Operating Expenses

Fuel, including purchased power, and plant operations increased $15.9 million for the first quarter of 2002, compared to the first quarter of 2001. The
2002 increase was primarily due to higher purchased power at the First Hydro plant. This increase reflects the changes under the new electricity trading arrangements, whereby First Hydro has purchased
electricity to meet sales commitments when it was
more cost-effective to purchase than to generate electricity, thus, reducing the need for physical pumping or generating. In addition, due to the new trading arrangements, some costs
previously paid by suppliers now are being paid by generators and all market participants are being charged imbalance costs when their metered position differs from their contracted position. The new
electricity trading arrangements are described in further detail under "Market Risk ExposuresUnited Kingdom."

Operating Income

Operating income increased $10 million during the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was due to equity in
income from investments discussed above.

Corporate/Other

Three Months Ended
March 31,2002

2001(Unaudited)
(in millions)Revenues:Net gains from energy trading and price risk management

$


$
0.9Expenses:Depreciation and amortization


2.1


2.8Long-term incentive compensation


1.7


(3.7
)Administrative and general


37.2


30.2Operating loss

$
(41.0
)
$
(28.4
)


Net
gains from price risk management activities recorded at fair value were $0.9 million for the first quarter of 2001. The gains primarily resulted from the change in market
value of our interest rate swaps with respect to our $100 million senior notes that did not qualify for hedge accounting under SFAS No. 133.

Long-term
incentive compensation expense consists of charges related to our terminated phantom option plan. The 2002 compensation expense is related to the annual vesting of
benefits. During the first quarter of 2001, an adjustment was made to reflect the decrease in market value of stock equivalent units.

Administrative
and general expenses increased $7 million for the first quarter of 2002, compared to the same prior year period. The 2002 increase was primarily due to a pretax
charge of approximately $4.1 million against first quarter earnings for severance and other related costs. The charge resulted from a series of actions undertaken by us designed to reduce
administrative and general operating costs, including reductions in management and administrative personnel.

24

---

Other Income (Expense)

Interest and other income (expense) decreased $1.4 million for the first quarter of 2002, compared to the first quarter of 2001. The decrease was primarily
due to lower interest income.

Interest
expense decreased $12.5 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 decrease was due to a combination of the following: a
reduction in corporate debt from the proceeds of the sale-leaseback of the Homer City facilities in December 2001 and lower borrowings combined with lower interest rates on variable
rate debt tied to LIBOR; partially offset by higher cost borrowings during the second and third quarters of 2001 and higher interest margins on our corporate line of credit.

Provision (Benefit) for Income Taxes

During the first quarter of 2002, we recorded an effective tax benefit rate of 52% based on projected income for the year and benefits under our
tax-allocation agreement, compared to the annual effective tax provision rate for the first quarter of 2001 of 37%. The effective tax rate increased as a result of a decrease in
anticipated income from operations in the United Kingdom.

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

Minority Interest

Minority interest expense increased $4.9 million for the first quarter of 2002, compared to the first quarter of 2001. The 2002 increase was due to
accounting for Contact Energy on a consolidated basis, effective June 1, 2001, due to the purchase of additional shares of Contact Energy that increased our ownership interest from 42.6% to a
controlling interest of 51.2%.

Discontinued Operations

As a result of the change in the prices of power in the U.K. and the anticipated negative impacts of such changes on earnings and cash flow, we offered for sale
through a competitive bidding process the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. On December 21, 2001, we completed the sale of the
power plants to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated
with the plants. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have
been reflected as discontinued operations in the consolidated financial statements.

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

25

---

Cumulative Effect of Change in Accounting Principle

Accounting for Derivatives and SFAS No. 133

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

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

Accounting
for derivatives under SFAS No. 133 is complex. Each transaction requires an assessment of whether it is a derivative according to the definition under SFAS
No. 133, including amendments and interpretations. Transactions that do not meet the definition of a derivative are accounted by us on the accrual basis, unless they relate to our trading
operations, in which case they are accounted for using the fair value method under EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The
majority of our physical long-term power and fuel contracts, and the similar business activities of our affiliates, either do not meet the definition of a derivative or qualify for the
normal purchases and sales exception.

As
a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under the prior accounting policy.



On January 1, 2001, we recorded a $0.2 million, after tax, increase to income from continuing operations and a $230.2 million, after tax,
decrease to other comprehensive income as the cumulative effect of the adoption of SFAS No. 133. The following material items were recorded at fair value:



26

---



Under
SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective
portion, is immediately recognized in earnings. We recorded a net gain (loss) of approximately $(734,000) and $155,000 during the first quarter of 2002 and 2001, respectively, representing the amount
of cash flow hedges' ineffectiveness, reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement.

27

---



LIQUIDITY AND CAPITAL RESOURCES

At March 31, 2002, we had cash and cash equivalents of $368.6 million and had available a total of $694.3 million of borrowing capacity under
our $750 million corporate credit facility. The credit facility includes a one-year $538.3 million component, Tranche A, that expires on September 17, 2002 and a
three-year $211.7 million component, Tranche B, that expires on September 17, 2004. The credit facility provides credit available in the form of cash advances or letters of
credit. At March 31, 2002, there were no cash advances outstanding under either Tranche and $55.7 million of letters of credit outstanding under Tranche B. In addition to the interest
payments, we pay a facility fee as determined by our long-term credit ratings (0.625% and 0.75% at March 31, 2002 for Tranche A and Tranche B, respectively) on the entire credit
facility independent of the level of borrowings. See "Corporate Financing Plans."

Discussion of Historical Cash Flow

Cash Flows From Operating Activities

Net cash provided by (used in) operating activities:

Three Months Ended
March 31,2002

2001(Unaudited)
(in millions)Continuing operations

$
18.5

$
(170.8
)Discontinued operations


(7.2
)

32.6$
11.3

$
(138.2
)


The
higher operating cash flow from continuing operations in 2002, compared to 2001, reflects higher distributions from energy projects. In March 2002, we received distributions
from our investments in partnerships subsequent to their receipt of payments of past due accounts receivable from Southern California Edison. Lower distributions from energy projects in 2001 primarily
resulted from the delay in payments from the California utilities to our investments in California qualifying facilities. The change in operating cash flow from continuing operations in 2002 was also
due to the timing of cash payables related to working capital items. Net working capital at March 31, 2002 was $507.1 million compared to $324.6 million at December 31,
2001.

Cash
provided by operating activities from discontinued operations in 2001 reflects operating gains from the Ferrybridge and Fiddler's Ferry power plants during the first quarter of
2001.

Cash Flows From Financing Activities

Net cash provided by (used in) financing activities:

Three Months Ended
March 31,2002

2001(Unaudited)
(in millions)Continuing operations

$
(30.5
)
$
171.6Discontinued operations





(280.2
)$
(30.5
)
$
(108.6
)


Cash
used in financing activities from continuing operations in 2002 consisted of net payments of $80 million on our $750 million corporate credit facility and
$22 million related to Edison Mission Energy Funding Corp. In addition, a wholly-owned subsidiary borrowed $84 million under a loan

28

---

agreement in January 2002. For further discussion of the loan agreement, see "Subsidiary Financing Plans." Cash provided by financing activities from continuing operations in 2001
consisted of issuances under our corporate credit facilities. As of March 31, 2002, we had recourse debt of $2 billion, with an additional $4.1 billion of non-recourse
debt (debt which is recourse to specific assets or subsidiaries, but not to Edison Mission Energy) on our consolidated balance sheet.

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

Cash Flows From Investing Activities

Net cash used in investing activities:

Three Months Ended
March 31,2002

2001(Unaudited)
(in millions)Continuing operations

$
(1.1
)
$
(225.1
)Discontinued operations





(4.1
)$
(1.1
)
$
(229.2
)


Cash
used in investing activities from continuing operations in 2002 included $80 million paid for the purchase of a power sales agreement held by a third party. We invested
$72.1 million in the first quarter of 2002 in new plant and equipment principally related to the Valley Power project in Australia, the Illinois Plants and the Homer City facilities. Also,
included in 2002 capital expenditures were payments for three turbines purchased under the Edison Mission Energy Master Turbine Lease with funds from restricted cash of $61.1 million. We plan
to use these turbines for a new gas-fired project. Included in 2002 investing activities was $86 million of restricted cash used to purchase the three turbines and satisfy our
obligation related to the termination of the Edison Mission Energy Master Turbine Lease, thereby reducing our restricted cash account. We received proceeds of $44 million from the sales of our
50% interest in the Commonwealth Atlantic and James River projects and our 30% interest in the Harbor project during the first quarter of 2002. In addition, we received $78.5 million as a
return on 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.

Cash
used in investing activities from continuing operations in 2001 included cash used by us for equity contributions totaling approximately $115 million through March 31,
2001 to meet capital calls by partnerships that were owed money by Southern California Edison and Pacific Gas and Electric, following the failure by those entities to pay amounts due for power sold
under those agreements. Southern California Edison repaid all outstanding amounts on March 1, 2002, and Pacific Gas and Electric is making payments against defaulted amounts on a schedule that
should allow for payment in full by the end of the first quarter of 2003. In addition, we paid $20 million as part of the purchase of our 50% interest in the CBK project. We also invested
$75 million in the first quarter of 2001 in new plant and equipment principally related to the Homer City facilities and the Illinois Plants.

Corporate Financial Ratios

In assessing our leverage as a holding company and our ability to meet debt service obligations, we and our principal bank lenders use two primary ratios: a
recourse debt to recourse capital ratio and an
interest coverage ratio. These ratios are determined in accordance with financial covenants that have been included in our corporate credit facilities and are not determined in accordance with
generally accepted accounting principles as reflected in our Consolidated Statements of Cash Flows. Accordingly, these ratios should not be considered in isolation or as a substitute for cash flows
from operating

29

---

activities or cash flow statement data set forth in our Consolidated Statement of Cash Flows. While the ratios included in our corporate credit facilities measure the leverage and ability of Edison
Mission Energy to meet its debt service obligations, they do not measure the liquidity or ability of our subsidiaries to meet their debt service obligations. Furthermore, these ratios are not
necessarily comparable to other similarly titled captions of other companies due to differences in methods of calculations.

Our
corporate credit facilities include covenants tied to these financial ratios(1):

Financial Ratio

Covenant

Actual at
March 31, 2002

DescriptionRecourse Debt to Recourse Capital Ratio

Less than or
equal to
67.5%

63.1%

Ratio of (a) senior recourse debt to (b) sum of (i) shareholder's equity per our balance sheet adjusted by comprehensive income after December 31, 1999,plus(ii) senior recourse debtInterest Coverage Ratio

Greater than
or equal to
1.50 to 1.00

1.74 to 1.00

For prior 12-month period, ratio of (a) funds flow from operations to (b) interest expense on senior recourse debt


---

At
March 31, 2002, we met the above financial covenants. The actual interest coverage ratio during 2001 and the twelve months ended March 31, 2002 was adversely affected by
the operating results of the Ferrybridge and Fiddler's Ferry projects in the United Kingdom. The interest coverage ratio, excluding the activities of the Ferrybridge and Fiddler's Ferry projects, was
2.03 to 1 for the twelve months ended March 31, 2002. Compliance with these covenants is subject to future financial performance, including items that are beyond our control.

Our
interest coverage ratio for the four quarters ended March 31, 2002 was 1.74 to 1. Accordingly, under the "ring-fencing" provisions of our articles of incorporation
and bylaws, until our interest coverage ratio exceeds 2.2 to 1 for the immediately preceding four quarters, we can only pay dividends if we have an investment grade rating and have received rating
agency confirmation that a dividend will not result in a downgrade or have received unanimous approval of our board of directors, including our independent director. We have not paid or declared a
dividend to Mission Energy Holding Company during the first quarter of 2002.

30

---

Discussion of Recourse Debt to Recourse Capital Ratio

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

March 31,
2002

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

$
63.7

$
203.6Senior Notes


1,700.0


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


1,412.9


1,431.9Coal and Capex Facility


196.6


251.6Other


46.2


46.3Total Recourse Debt to Edison Mission Energy

$
3,419.4

$
3,633.4Recourse Capital

$
2,003.6

$
2,039.0Total Capitalization

$
5,423.0

$
5,672.4Recourse Debt to Resource Capital Ratio


63.1%


64.1%


---

During
the quarter ended March 31, 2002, the recourse debt to recourse capital ratio improved due to:



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

31

---

Discussion of Interest Coverage Ratio

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

March 31,
2002

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

$
221.5

$
201.3Homer City


134.3


175.2Ferrybridge and Fiddler's Ferry


(101.9
)

(104.5
)First Hydro


46.0


45.9Other consolidated operating projects


66.5


64.1Trading and price risk management


33.3


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


210.9


128.8Distributions from other non-consolidated operating projects


89.7


93.5Interest income


8.7


9.0Operating expenses


(151.1
)

(143.1
)Total funds flow from operations


557.9


498.4Interest Expense


320.2


304.8Interest Coverage Ratio


1.74


1.64


---

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



32

---



Interest
expense increased $15.4 million during the twelve months ended March 31, 2002 from the year ended December 31, 2001 as a result of:



Credit Ratings

To isolate ourselves from the impact of the California power crisis on Edison International and Southern California Edison, and to facilitate our ability and the
ability of our subsidiaries to maintain our respective investment grade credit ratings, on January 17, 2001, we amended our articles of incorporation and our bylaws to include
so-called "ring-fencing" provisions. These ring-fencing provisions are intended to preserve us as a stand-alone investment grade rated entity. These provisions
require the unanimous approval of our board of directors, including at least one independent director, before we can do any of the following:



In
January 2001, Standard & Poor's and Moody's downgraded our senior unsecured credit ratings to "BBB-" from "A-" and to "Baa3" from "Baa1,"
respectively. Our credit ratings remain investment grade. Maintaining our investment grade credit ratings is part of our current operational focus and our long-term strategy. However, we
cannot assure you that Standard & Poor's and Moody's will not downgrade our credit rating below investment grade. If our credit ratings are downgraded below investment grade, we could be
required to, among other things:



A
downgrade of our credit ratings could result in a downgrade of the credit rating of Edison Mission Midwest Holdings Co., our indirect subsidiary. In the event of a downgrade of Edison
Mission Midwest Holdings below investment grade, provisions in the agreements binding on its subsidiary, Midwest Generation, LLC, would limit the ability of Midwest Generation to use excess cash flow
to make distributions.

33

---

A
downgrade of our credit ratings below investment grade could increase our cost of capital, increase our credit support obligations, make efforts to raise capital more difficult and
have an adverse impact on us and our subsidiaries. In addition, in order to continue to market the power from our Homer City facilities and First Hydro plants in the United Kingdom as well as purchase
natural gas or fuel oil at our Illinois Plants, we may be required to provide substantial additional credit support in the form of letters of credit or cash. In addition, changes in forward market
prices and margining requirements could further increase the need for credit support for our trading and risk management activities.

Standard &
Poor's and Moody's have indicated that they are reviewing the criteria for assessing credit risk for merchant energy companies (companies that generate and/or trade
wholesale power without long-term contracts). The criteria used by Standard & Poor's and Moody's in assessing credit risk in turn is used to assign credit ratings, including whether
or not a company is investment grade. We cannot predict whether Standard & Poor's or Moody's will change their criteria for assessing credit risk or, if changes were made, whether or not such
changes would adversely affect our credit ratings.

Corporate Financing Plans

We have a $750 million corporate credit facility which includes a one-year $538.3 million component, Tranche A, that expires on
September 17, 2002 and a three-year $211.7 million component, Tranche B, that expires on September 17, 2004. At March 31, 2002, we had borrowing capacity under
this facility of $694.3 million and corporate cash and cash equivalents of $44.7 million. We plan to utilize the corporate credit facilities to fund corporate expenses, including
interest, during 2002, as necessary depending on the timing and amount of distributions from our subsidiaries. Our first quarter 2002 cash flow includes distributions from our investments in
partnerships made subsequent to their receipt of payments of past due accounts receivable from Southern California Edison on March 1, 2002. Total amounts paid to these partnerships by Southern
California Edison was $415 million, of which our share was $206.2 million. In addition, we expect to receive in 2002 tax-allocation payments of our outstanding receivable of
$224.4 million at March 31, 2002 from our ultimate parent company. In addition, we plan to extend Tranche A under our corporate facility or enter into a similar facility with other
financial institutions by September 2002. The timing and amount of distributions from our subsidiaries may be affected by many factors beyond our control, some of which are described under
"Risk Factors" included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2001.

Subsidiary Financing Plans

The estimated capital and construction expenditures of our subsidiaries for the final three quarters of 2002 are $106.6 million. These expenditures are
planned to be financed by existing subsidiary credit agreements and cash generated from their operations, except with respect to the Homer City project. Under the Homer City sale-leaseback
agreements, we have committed to provide funds for capital expenditures needed by the power plant. We expect to contribute $17.6 million in 2002 to fund the estimated capital expenditures of
this project, of which $4.9 million was contributed during the first quarter of 2002. See "Note 6. Commitments and Contingencies."

Loan Agreement in Connection with Power Sales Agreement

In connection with the restructuring of the power sales agreement with an unaffiliated electric utility, a wholly-owned subsidiary borrowed $84 million
under a loan agreement to finance the purchase of the power sales agreement held by a third party, make a deposit under a power supply contract, and pay for transaction costs. The loan is secured by
the payments from the power sales agreement and is non-recourse to us. The interest rate under the loan agreement is fixed at 7.31% and is due in

34

---

June 2015. Principal payments under the loan agreement are $0.4 million in 2002, $0.8 million in 2003, $1.5 million in 2004, $2.2 million in 2005,
$3.0 million in 2006 and $76 million due after 2006.

Intercompany Tax-Allocation Payments

We participate in a tax-allocation agreement with The Mission Group, which in turn participates in a tax-allocation agreement with Edison
International. We have historically received tax payments under the tax-allocation agreement related to domestic net operating losses incurred by us. However, we were required to pay
Edison International $55 million during October 2001 primarily as a result of changes in estimated taxable income for 2000. At March 31, 2002, we have recorded
$224.4 million as an income tax receivable under the tax-allocation agreement. However, we are not eligible to receive tax-allocation payments for such losses until such
time as Edison International and its subsidiaries generate sufficient taxable income in order to be able to utilize our tax losses in the consolidated income tax returns for Edison International and
its subsidiaries. We anticipate this will occur in 2002, and, accordingly, we expect to receive payments in 2002 of our outstanding receivable from Edison International.

Restricted Assets of Subsidiaries

Each of our direct and indirect subsidiaries is organized as a legal entity separate and apart from us and our other subsidiaries. Assets of our subsidiaries may
not be available to satisfy our obligations or the obligations of any of our other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to
applicable law and the terms of financing arrangements of the subsidiaries, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or to an affiliate of ours.

Market Risk Exposures

Our primary market risk exposures arise from changes in electricity and fuel prices, interest rates and fluctuations in foreign currency exchange rates. We manage
these risks in part by using derivative financial instruments in accordance with established policies and procedures.

Commodity Price Risk

Energy trading and price risk management activities give rise to commodity price risk, which represents the potential loss that can be caused by a change in the
market value of a particular commodity. Commodity price risks are actively monitored to ensure compliance with our risk management policies. Policies are in place which limit the amount of total net
exposure we may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with daily reporting to senior management. We perform a "value at risk"
analysis in our daily business to measure, monitor and control our overall market risk exposure. The use of value at risk allows management to aggregate overall risk, compare risk on a consistent
basis and identify the drivers of the risk. Value at risk measures the worst expected loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent
limitations of value at risk and relying on a single risk
measurement tool, we supplement this approach with the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits.

Electric
power generated at our merchant plants is generally sold under bilateral arrangements with utilities and power marketers under short-term contracts with terms of two
years or less, or, in the case of the Homer City facilities, to the Pennsylvania-New Jersey-Maryland Power Pool (PJM) or the New York Independent System Operator (NYISO). Our risk
management policies and procedures include an assessment of credit risk. When making sales under negotiated bilateral contracts, it is our general policy to deal with investment grade counterparties
or counterparties that have equivalent

35

---

credit quality. Our risk management committees grant exceptions to the policy only after review and scrutiny. Most entities that have received exceptions are typically organized power pools and
quasi-governmental agencies. We hedge a portion of the electric output of our merchant plants, whose output is not committed to be sold under long-term contracts, in order to provide more
predictable earnings and cash flow. When appropriate, we manage the spread between electric prices and fuel prices, and use forward contracts, swaps, futures, or options contracts to achieve those
objectives.

Our
revenues and results of operations during the estimated useful lives of our merchant power plants will depend upon prevailing market prices for capacity, energy, ancillary services,
fuel oil, coal and natural gas and associated transportation costs in the market areas where our 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



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

The
following table depicts the average markets prices per megawatt hour in PJM during the first quarters of 2002 and 2001:

24-Hour PJM Prices*2002

2001January

$
20.52

$
36.66February


20.62


29.53March


24.27


35.05Quarterly Average

$
21.80

$
33.75


---

As
shown on the above table, the average market prices during the first three months of 2002 are below the average market prices during the first three months of 2001. The forward market
prices in PJM 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. For

36

---

example, during April 2002, our forecasted yearly average 24-hour PJM prices for 2002 ranged from approximately $23.25 to $31.21, compared to the actual yearly average
24-hour PJM prices of $29.07 in 2001. Our forecasted yearly average 24-hour PJM prices are based on year-to-date actual data and a forecast for the
remainder of the year based on current market information.

The
ability of our subsidiary, EME Homer City, to make payments under the long-term lease entered into as part of the sale-leaseback transaction discussed under
"Off-Balance Sheet TransactionsSale-Leaseback Transactions," included in Item 7 of Edison Mission Energy's Annual Report on
Form 10-K for the year ended December 31, 2001, is dependent on revenues generated by the Homer City facilities, which depend on market conditions for the sale of capacity
and energy. These market conditions are beyond our control.

Illinois Plants

Electric power generated at the Illinois Plants is sold under three power purchase agreements with Exelon Generation Company, in which Exelon Generation purchases
capacity and has the right to purchase energy generated by the Illinois Plants. The agreements, which began on December 15, 1999 and have a term of up to five years, provide for capacity and
energy payments. Exelon Generation is obligated to make a capacity payment for the plants under contract and an energy payment for the electricity produced by these plants and taken by Exelon
Generation. The capacity payments provide the Illinois Plants revenue for fixed charges, and the energy payments compensate the Illinois Plants for variable costs of production.

Virtually
all of the energy and capacity sales in the first quarter of 2002 from the Illinois Plants were made to Exelon Generation under the power purchase agreements, and is expected
to continue to be sold to Exelon Generation during the remainder of 2002. In October 2001, Exelon Generation exercised
the option under one of the power purchase agreements to terminate all of the oil peaker plants (300 megawatts), effective January 2002, but continued it with respect to all other peaker plants
for 2002. In each of 2003 and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any of the remaining coal units and
all of the natural gas and oil-fired units with prior notice as specified under each agreement.

The
energy and capacity from any units which do not remain subject to one of the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity,
to be negotiated with customers or into the so-called spot market. Thus, to the extent that Exelon Generation does not purchase our power for 2003 or 2004, we will be subject to the market
risks related to the price of energy and capacity described above. Due to the volatility of market prices for energy and capacity during the past several years, we cannot predict whether or not Exelon
Generation will elect to terminate any of the units currently subject to the power purchase agreements for which termination is permitted and, if they do, whether sales of energy and capacity to other
customers and the market will be at prices sufficient to generate cash flow necessary to meet the obligations of our subsidiary. As of March 31, 2002, we had not entered into forward energy
sales contracts for the Illinois Plants other than those with Exelon Generation.

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Europe and Middle East

United Kingdom

Since 1989, our plants in the U.K. have sold their electrical energy and capacity through a centralized electricity pool, which established a
half-hourly clearing price, also referred to as the pool price, for electrical energy. On March 27, 2001, this system was replaced by the U.K. government with a bilateral physical
trading system referred to as the new electricity trading arrangements. In connection with the new electricity trading arrangements, the First Hydro plant entered into forward contracts with varying
terms that expire on various dates through October 2003. In addition, two long-term contracts with a three-year termination provision entered into in March 1999
from the First Hydro plant to buy and sell electricity were amended as forward contracts.

The
new electricity trading arrangements provide for, among other things, the establishment of a range of voluntary short-term power exchanges and brokered markets operating
from a year or more in advance to 3.5-hours before a trading period of one-half hour; a balancing mechanism to enable the system operator to balance generation and demand and
resolve any transmission constraints; a mandatory settlement process for recovering imbalances between contracted and metered volumes with strong incentives for being in balance; and a Balancing and
Settlement Code Panel to oversee governance of the balancing mechanism. The grid operator retains the right under the new market mechanisms to purchase system reserve and response services to maintain
the quality of the electrical supply directly from generators (generally referred to as "ancillary services"). Ancillary services contracts typically run for a year and can consist of both fixed
amounts and variable amounts represented by prices for services that are only paid for when actually called upon by the grid operator. Physical bilateral contracts have replaced the prior financial
contracts for differences, but have a similar commercial function. A key feature of the new arrangements is to require firm physical delivery, which means that a generator must deliver, and a consumer
must take delivery of, its net contracted positions or pay for any energy imbalance at highly volatile imbalance prices calculated by the market operator. A consequence of this new system has been to
increase greatly the motivation of parties to contract in advance and to further develop forwards and futures markets of greater liquidity than at present. Furthermore, another consequence of the
market change is that counterparties may require additional credit support, including parent company guarantees or letters of credit.

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

During
2001, our operating income from the First Hydro plant decreased $105.9 million from the prior year primarily due to the removal of a formal capacity mechanism in the new
trading arrangements and the oversupply of generation in the market resulting in a sharp fall in the market value for capacity. In addition, First Hydro's operating results have been adversely
impacted in the second half of 2001 by a fall in the differential of the peak daytime energy price compared to the cost of purchasing power at nighttime to pump water back to the top reservoir.
Generation capacity on the U.K. system has been in excess of demand due to generators holding plant on the system at part load to protect themselves against the adverse affects of being out of balance
in the new market and the mild weather experienced during 2001.

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For
the foregoing reasons, First Hydro's interest coverage ratio, when measured for the twelve-month period ended June 30, 2002, may be below the threshold set forth in its bond
financing documents, although it is anticipated that current project revenues will enable the July 31, 2002 interest payment to be made without recourse to the project's debt service reserve.
We believe that should market and trading conditions experienced thus far in 2002 be sustained for the balance of the year, First Hydro's interest coverage ratio will be above the required threshold
when measured for the twelve-month period ended December 31, 2002. Compliance by First Hydro with these and other requirements of its bond financing documents are subject, however, to market
conditions for the sale of energy and ancillary services. These market conditions are beyond our control. There is no assurance that these requirements will be met and, if not met, will be waived by
the holders of First Hydro's bonds. The bond financing documents stipulate that a breach of a financial covenant constitutes an immediate event of default and, if the event of default is not waived or
cured, the holders of the First Hydro bonds are entitled to enforce their security over First Hydro's assets, including its power plants.

Asia Pacific

Australia.The Loy Yang B plant sells its electrical energy through a centralized electricity pool, which provides for a
system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management
Company, operator and administrator of the pool, determines a system marginal price each half-hour. To mitigate exposure to price volatility of the electricity traded into the pool, the
Loy Yang B plant has entered into a number of financial hedges. The State Hedge agreement with the State Electricity Commission of Victoria is a long-term contractual arrangement based
upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State Government of Victoria, Australia guarantees the State Electricity Commission of Victoria's
obligations under the State Hedge. From January 2001 to July 2014, approximately 77% of the plant output sold is hedged under the State Hedge. From August 2014 to
October 2016, approximately 56% of the plant output sold is hedged under the State Hedge. Additionally, the Loy Yang B plant has entered into a number of derivative contracts to further
mitigate against price volatility inherent in the electricity pool. These contracts consist of fixed forward electricity contracts that expire on various dates through December 31, 2004, and a
five-year electricity cap contract expiring December 31, 2006.

New Zealand.A substantial portion of Contact Energy's generation output is hedged by sales to retail electricity customers and forward
contracts with other wholesale electricity counterparties. Contact Energy has entered into forward contracts and option contracts of varying terms that expire on various dates through April 1,
2004 and January 31, 2004, respectively. The New Zealand Government commissioned an inquiry into the electricity industry in February 2000. Following the inquiry report the New Zealand
Government released a Government Policy Statement, at the center of which was a call for the industry to rationalize the three existing industry codes, form a single governance structure and
address transmission pricing methodology. The Government Policy Statement also requested a model use of system agreement be agreed, that is a framework by which the retailers contract for services
from each of the distribution networks, and a consumer complaints ombudsman be established. An essential theme throughout the Government Policy Statement was the desire that the industry retain a
private multilateral self-governing structure. During 2001, an amendment to the Electricity Act of 1992 was passed that laid out the form that regulation would take if the industry does
not heed the Government's call. Progress on the single governance code is well underway and the Chairs of the three existing codes report to the Minister of Energy every two months on progress. The
new code is likely to be introduced in July 2002. As a result of the winter energy crisis in 2001, the Government sponsored a review of the functioning of the wholesale electricity market. That
review has resulted in a proposal to require wholesale electricity generators to make available a minimum capacity for hedging agreements with large industrial and commercial customers. While we
cannot predict the outcome of this review,

39

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we do not believe that it will result in a change to the wholesale market or to the hedging practices of Contact Energy.

Interest Rate Risk

Interest rate changes affect the cost of capital needed to finance the construction and operation of our projects. We have mitigated the risk of interest rate
fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of our project financings.
Interest expense included $10.2 million and $2.8 million of additional interest expense for the three months ended March 31, 2002 and 2001, respectively, as a result of interest
rate hedging mechanisms. We have entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt.

We
had short-term obligations of $95.3 million at March 31, 2002, consisting of borrowings under a construction facility for the Valley Power project and a
floating rate loan related to the Contact Energy project. The fair values of these obligations approximated their carrying values at March 31, 2002, and would not have been materially affected
by changes in market interest rates. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of our total
long-term obligations (including current portion) was $6 billion at March 31, 2002.

Foreign Exchange Rate Risk

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

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

During
the first quarter of 2002, foreign currencies in Australia and New Zealand increased in value compared to the U.S. dollar by 4.3% and 5.9%, respectively (determined by the change
in the exchange rates from December 31, 2001 to March 31, 2002). The increase in value of these currencies was the primary reason for the foreign currency translation gain of
$15.8 million during the first quarter of 2002.

Contact
Energy enters into foreign currency forward exchange contracts to hedge identifiable foreign currency commitments associated with transactions in the ordinary course of business.
The contracts are primarily in Australian and U.S. dollars with varying maturities through October 2002. At March 31, 2002, the outstanding notional amount of the contracts totaled
$20.2 million and the fair value of the contracts totaled $(0.5) million. During the first quarter of 2002, Contact Energy recognized a foreign exchange loss of $0.4 million related to
the contracts that matured during the same period.

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In
addition, Contact Energy enters into cross currency interest rate swap contracts in the ordinary course of business. These cross currency swap contracts involve swapping fixed and
floating-rate U.S. and Australian dollar loans into floating-rate New Zealand dollar loans with varying maturities through April 2018. At March 31, 2002, Contact
Energy had cross currency swap contracts in place with an approximate net-hedged value of $16.8 million. During the first quarter of 2002, Contact Energy recognized a gain of
$3.9 million related to the termination of cross currency swap contracts.

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

Non-Trading Derivative Financial Instruments

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

March 31,
2002

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

$
(21.9
)
$
(35.8
)Interest rate options


0.3


(1.0
)Commodity price:Forwards


49.2


63.8Futures


(7.0
)

(8.4
)Options





0.4Swaps


(119.9
)

(137.6
)Foreign currency forward exchange agreements


(0.5
)

(0.6
)Cross currency interest rate swaps


16.8


27.6


In
assessing the fair value of our non-trading derivative financial instruments, we use a variety of methods and assumptions based on the market conditions and associated
risks existing at each balance sheet date. The fair value of commodity price contracts takes in account quoted marked prices, time value of money, volatility of the underlying commodities and other
factors.

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

Energy Trading

On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our operations beyond the
traditional marketing of our electric power to include trading of electricity and fuels. In conducting our trading activities, we seek to generate profit from price volatility of electricity and fuels
by buying and selling these commodities in wholesale markets. We generally balance forward sales and purchases contracts and manage our exposure through a value at risk analysis as described further
below. We also conduct price risk management activities with third parties not related to our power plants or investments in energy projects, including the restructuring of power sales and power
supply agreements.

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

March 31, 2002

December 31, 2001Assets

Liabilities

Assets

Liabilities(Unaudited)Forward contracts

$
98.3

$
4.8

$
4.6

$
2.9Futures contracts








0.1


0.1Option contracts


0.5


0.2





Swap agreements


10.4


10.5


0.2


Total

$
109.2

$
15.5

$
4.9

$
3.0


Quoted
market prices are used to determine the fair value of the financial instruments related to trading activities, except for the power sales agreement with an unaffiliated electric
utility that we purchased and restructured and a long-term power supply agreement with another unaffiliated party. We recorded these agreements at fair value based upon a discounting of
future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of the power supply
agreement.

Off-Balance Sheet Transactions

For a complete discussion of Edison Mission Energy's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" in Item 7
of Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

Environmental Matters and Regulations

For a complete discussion of Edison Mission Energy's environmental matters, refer to "Environmental Matters and Regulations" in Item 7 of Edison Mission Energy's
Annual Report on Form 10-K for the fiscal year ended December 31, 2001 or the notes to the Consolidated Financial Statements set forth therein. There have been no significant
developments with regard to environmental matters that affect disclosures presented as of December 31, 2001.

Critical Accounting Policies

For a complete discussion of Edison Mission Energy's critical accounting policies, refer to "Critical Accounting Policies" in Item 7 of Edison Mission Energy's
Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

New Accounting Standards

In December 2001, the Derivative Implementation Group issued a revised interpretation of "Normal Purchases and Normal Sales Exception for Certain
Option-Type Contracts and Forward Contracts in Electricity" (referred to as Statement No. 133 Implementation Issue Number C15). Under this revised interpretation, our forward
electricity contracts from our Homer City facilities will no longer qualify for the normal sales exception since we have net settlement agreements with our counterparties. In lieu of following this
exception in which we record revenue on an accrual basis, we believe our forward sales agreement will qualify as cash flow hedges. Under a cash flow hedge, we will record the fair value of the forward
sales agreements on our consolidated balance sheet and record the effective portion of the cash flow hedge as part of accumulated other comprehensive income. The ineffective portion of our cash flow
hedges will be recorded directly in our consolidated income statement. This revised interpretation became effective April 1, 2002. We expect to record

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approximately $11.9 million as the fair value of the forward electricity contracts and a cumulative change in other comprehensive income of a like amount.

Currently,
we are using the normal sales and purchases exception for some of our fuel supply agreements. However, in October 2001, the Derivative Implementation Group of the
Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C16 issued guidance that precludes contracts that have variable quantities from qualifying under the
normal sales and purchases exception unless such quantities are contractually limited to use by the purchaser. We do not believe implementation of this new interpretation, which became effective on
April 1, 2002, will have a material effect.

In
October 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." The Statement establishes accounting and reporting standards for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" but retains SFAS No. 121 requirements to recognize an
impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and to measure an impairment loss as the difference between the
carrying amount and fair value of the asset less cost to sell, whether reported in continuing operations or in discontinued operations. In addition, SFAS No. 144 broadens the reporting of
discontinued operations to include a component of an entity (rather than a segment of a business) that has been disposed of or is classified as held for sale. The standard, effective on
January 1, 2002, was adopted by us in the fourth quarter of 2001, which required the sale of the Ferrybridge and Fiddler's Ferry power plants to be accounted for as discontinued operations. See
"Discontinued Operations," for further discussion.

In
August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," which
will be effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred.
When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its
present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded
amount or incurs a gain or loss upon settlement. We are studying the effects of the new standard.

Effective
January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 establishes
accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. A benchmark assessment for goodwill is
required no later than June 30, 2002. The Statement requires that goodwill should be tested for impairment using a two-step approach. The first step used to identify a potential
impairment compares the fair value of a reporting unit to its carrying amount, including goodwill. If the fair value of the reporting unit is less than its carrying amount, the second step of the
impairment test is performed to measure the amount of the impairment loss. The second step of the impairment test is a comparison of the implied fair value of goodwill to its carrying amount. The
impairment loss is equal to the excess carrying amount of the goodwill over the implied fair value. Goodwill on our consolidated balance sheet at December 31, 2001 totaling
$631.7 million is comprised of $359.5 million related to the Contact Energy acquisitions, $247.4 million related to the First Hydro acquisition and $24.8 million related to
the Citizens Power LLC acquisition. We did not record amortization of goodwill of approximately $5.2 million during the first quarter of 2002 in accordance with the provision of this Statement.
We are in the process of completing an appraisal of our reporting units under the first step discussed above, which we plan to complete by June 30, 2002.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a complete discussion of market risk sensitive instruments, refer to "Market Risk Exposures" in Item 7 of Edison Mission Energy's Annual Report on
Form 10-K for the fiscal year ended December 31, 2001. Refer to "Market Risk Exposures" in Item 2 for an update to that disclosure.

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PART IIOTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Sunrise Regulatory Proceedings

Sunrise Power Company, in which we own a 50% interest, sells all of its output to the California Department of Water Resources under a power purchase agreement
entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the Federal Energy
Regulatory Commission against all sellers of long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California Public Utilities
Commission complaint alleged that the contracts are "unjust and unreasonable" on price and other terms, and requests that the contracts be abrogated. The California Electricity Oversight Board
complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water. Sunrise filed a motion to dismiss with the Federal Energy
Regulatory Commission requesting, among other things, a dismissal of both complaints and expedited treatment of its motion, and both the California Public Utilities Commission and the California
Electricity Oversight Board have filed responses to the motions of Sunrise and other defendants. On April 25, 2002, the Federal Energy Regulatory Commission denied Sunrise's motion to dismiss
the complaints and set hearings on the contracts executed prior to June 20, 2001, but was silent as to what, if any, actions it intended to take with respect to contracts, including the Sunrise
contract, executed after that date. Sunrise has filed a motion seeking confirmation from the Federal Energy Regulatory Commission that it does not intend to review contracts executed after
June 20, 2001 or, in the alternative, requesting a rehearing regarding the denial of its motion to dismiss.

On
May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Los Angeles Superior Court 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 of the
contracts entered into in 2001, as well as all of the contracts renegotiated in 2002, as a result of a purported conflict of interest by Mr. Budhraja. Sunrise Power Company has not yet been
served with a copy of the complaint.

Paiton Labor Suit

In April 2001, Paiton Energy was sued in the Central Jakarta District Court by the PLN Labor Union. PT PLN, the Indonesian Minister of Mines and Energy and
the former President Director of PT PLN are also named as defendants in the suit. The union sought to set aside the power purchase agreement between Paiton Energy and PT PLN and the interim agreement
then in effect between Paiton Energy and its lenders, as well as damages and other relief. On April 16, 2002, the Central Jakarta District Court dismissed the lawsuit against Paiton Energy and
the other defendants on the basis that the PLN Labor Union was not authorized under the law to bring such an action. On April 23, 2001, the PLN Labor Union filed to appeal this decision. Paiton
Energy intends to contest the appeal.

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

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ITEM 6.    EXHIBITS AND REPORTS ON FORM 8-K

Exhibit No.

Description10.1

Terms of 2002 stock option and performance share awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended
March 31, 2002. (File No. 1-9936).


The
registrant filed the following reports on Form 8-K during the quarter ended March 31, 2002.

Date of Report

Date Filed

Item(s) ReportedDecember 21, 2001

January 7, 2002

2, 7December 21, 2001

March 6, 2002

7


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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)
| |  | ---------------------------------

|                  |  |                                                                                             
|----------------- |  | --------------------------------------------------------------------------------------------
|Date: May 8, 2002 |  | /s/KEVIN M. SMITHKEVIN M. SMITH Senior Vice President,
Chief Financial Officer and Treasurer

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