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

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Form 10-Q

(Mark One)

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

For the Quarterly Period Ended June 30, 2002

or

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

For the transition period from  to

Commission file number 000-24890

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

Delaware(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 August 9, 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 |  | 22  
|3.                           |  | Quantitative and Qualitative Disclosures About Market Risk                            |  | 64  
|PART IIOther Information   
|1.                           |  | Legal Proceedings                                                                     |  | 65  
|6.                           |  | Exhibits and Reports on Form 8-K                                                      |  | 67  
|                             |  | Signatures                                                                            |  | 69  

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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
June 30,  |       | Six Months Ended
June 30, |         
|---------------------------------------- | ------------------------------------------------------------------------------------- | ---------------------------- | ----- | ------------------------- | --------
|
|
|Operating Revenues                       |                                                                                       |                              |       |                           |         
|                                         | Electric revenues                                                                     |                              | $     | 679,122                   |         
|                                         | Equity in income from energy projects                                                 |                              |       | 52,604                    |         
|                                         | Equity in income from oil and gas investments                                         |                              |       | 3,642                     |         
|                                         | Net gains from energy trading and price risk management                               |                              |       | 3,241                     |         
|                                         | Operation and maintenance services                                                    |                              |       | 8,247                     |         
|                                         |                                                                                       |                              |       |                           |         
|                                         |                                                                                       | Total operating revenues     |       |                           | 746,856 
|                                         |                                                                                       |                              |       |                           |         
|Operating Expenses                       |                                                                                       |                              |       |                           |         
|                                         | Fuel                                                                                  |                              |       | 235,193                   |         
|                                         | Plant operations                                                                      |                              |       | 212,463                   |         
|                                         | Plant operating leases                                                                |                              |       | 51,266                    |         
|                                         | Operation and maintenance services                                                    |                              |       | 5,913                     |         
|                                         | Depreciation and amortization                                                         |                              |       | 63,074                    |         
|                                         | Long-term incentive compensation                                                      |                              |       | 2,042                     |         
|                                         | Administrative and general                                                            |                              |       | 41,287                    |         
|                                         |                                                                                       |                              |       |                           |         
|                                         |                                                                                       | Total operating expenses     |       |                           | 611,238 
|                                         |                                                                                       |                              |       |                           |         
|                                         | Operating income                                                                      |                              |       | 135,618                   |         
|                                         |                                                                                       |                              |       |                           |         
|Other Income (Expense)                   |                                                                                       |                              |       |                           |         
|                                         | Interest and other income                                                             |                              |       | 666                       |         
|                                         | Gain on sale of assets                                                                |                              |       |                          |         
|                                         | Interest expense                                                                      |                              |       | (114,571                  | )       
|                                         | Dividends on preferred securities                                                     |                              |       | (5,302                    | )       
|                                         |                                                                                       |                              |       |                           |         
|                                         |                                                                                       | Total other income (expense) |       |                           | (119,207
|                                         |                                                                                       |                              |       |                           |         
|                                         | Income (loss) from continuing operations before income taxes and minority interest    |                              |       | 16,411                    |         
|                                         | Provision (benefit) for income taxes                                                  |                              |       | 5,581                     |         
|                                         | Minority interest                                                                     |                              |       | (10,739                   | )       
|                                         |                                                                                       |                              |       |                           |         
|Income (Loss) From Continuing Operations |                                                                                       |                              | 91    |                           |         
|                                         | Income (loss) from operations of discontinued foreign subsidiary, net of tax (Note 4) |                              |       | 3,143                     |         
|                                         |                                                                                       |                              |       |                           |         
|Income (Loss) Before Accounting Change   |                                                                                       |                              | 3,234 |                           |         
|                                         | Cumulative effect of change in accounting, net of tax                                 |                              |       |                          |         
|                                         |                                                                                       |                              |       |                           |         
|Net Income (Loss)                        |                                                                                       | $                            | 3,234 |                           | $       
|                                         |                                                                                       |                              |       |                           |         

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
June 30,                                                                                                                                                                                                           |        | Six Months Ended
June 30, |        
|------------------------------------------------- | ----------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------ | ------------------------- | -------
|
|
|Net Income (Loss)                                 |                                                                         | $                                                                                                                                                                                                                                     | 3,234  |                           | $      
|Other comprehensive income (expense), net of tax: |                                                                         |                                                                                                                                                                                                                                       |        |                           |        
|                                                  | Foreign currency translation adjustments:                               |                                                                                                                                                                                                                                       |        |                           |        
|                                                  |                                                                         | Foreign currency translation adjustments, net of income tax expense (benefit) of $(2,978) and $316 for the three months and $(2,111) and $2,665 for the six months ended June 30, 2002 and 2001, respectively                         |        |                           | 63,396 
|                                                  | Unrealized gains (losses) on derivatives qualified as cash flow hedges: |                                                                                                                                                                                                                                       |        |                           |        
|                                                  |                                                                         | Cumulative effect of change in accounting for derivatives, net of income tax expense (benefit) of $5,562 for the three and six months ended June 30, 2002 and $(110,900) for the six months ended June 30, 2001                       |        |                           | 6,357  
|                                                  |                                                                         | Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(3,472) and $86,200 for the three months and $14,929 and $68,800 for the six months ended June 30, 2002 and 2001, respectively |        |                           | (23,004
|                                                  |                                                                         | Reclassification adjustments included in net income (loss), net of income tax benefit of $1,389 and $2,000 for the three months and $961 and $17,600 for the six months ended June 30, 2002 and 2001, respectively                    |        |                           | 2,588  
|                                                  |                                                                         |                                                                                                                                                                                                                                       |        |                           |        
|Other comprehensive income (expense)              |                                                                         |                                                                                                                                                                                                                                       | 49,337 |                           |        
|                                                  |                                                                         |                                                                                                                                                                                                                                       |        |                           |        
|Comprehensive Income (Loss)                       |                                                                         | $                                                                                                                                                                                                                                     | 52,571 |                           | $      
|                                                  |                                                                         |                                                                                                                                                                                                                                       |        |                           |        

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)

|                                  |                                                                                                   | June 30,
2002                     |            | December 31,
2001
|--------------------------------- | ------------------------------------------------------------------------------------------------- | --------------------------------- | ---------- | -----------------
|
|Assets                            |                                                                                                   |                                   |            |                  
|Current Assets                    |                                                                                                   |                                   |            |                  
|                                  | Cash and cash equivalents                                                                         |                                   | $          | 343,463          
|                                  | Accounts receivabletrade, net of allowance of $13,321 and $14,603 in 2002 and 2001, respectively |                                   |            | 377,162          
|                                  | Accounts receivableaffiliates                                                                    |                                   |            | 20,512           
|                                  | Assets under energy trading and price risk management                                             |                                   |            | 69,727           
|                                  | Inventory                                                                                         |                                   |            | 187,311          
|                                  | Prepaid expenses and other                                                                        |                                   |            | 71,874           
|                                  |                                                                                                   |                                   |            |                  
|                                  |                                                                                                   | Total current assets              |            |                  
|                                  |                                                                                                   |                                   |            |                  
|Investments                       |                                                                                                   |                                   |            |                  
|                                  | Energy projects                                                                                   |                                   |            | 1,619,927        
|                                  | Oil and gas                                                                                       |                                   |            | 20,262           
|                                  |                                                                                                   |                                   |            |                  
|                                  |                                                                                                   | Total investments                 |            |                  
|                                  |                                                                                                   |                                   |            |                  
|Property, Plant and Equipment     |                                                                                                   |                                   | 7,457,608  |                  
|                                  | Less accumulated depreciation and amortization                                                    |                                   |            | 845,566          
|                                  |                                                                                                   |                                   |            |                  
|                                  |                                                                                                   | Net property, plant and equipment |            |                  
|                                  |                                                                                                   |                                   |            |                  
|Other Assets                      |                                                                                                   |                                   |            |                  
|                                  | Long-term receivables                                                                             |                                   |            | 264,096          
|                                  | Goodwill                                                                                          |                                   |            | 682,359          
|                                  | Deferred financing costs                                                                          |                                   |            | 67,176           
|                                  | Long-term assets under energy trading and price risk management                                   |                                   |            | 111,490          
|                                  | Restricted cash and other                                                                         |                                   |            | 301,696          
|                                  |                                                                                                   |                                   |            |                  
|                                  |                                                                                                   | Total other assets                |            |                  
|                                  |                                                                                                   |                                   |            |                  
|Assets of Discontinued Operations |                                                                                                   |                                   | 13,483     |                  
|                                  |                                                                                                   |                                   |            |                  
|Total Assets                      |                                                                                                   | $                                 | 10,762,580 |                  
|                                  |                                                                                                   |                                   |            |                  

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)

|                                                |                                                                                                   | June 30,
2002                              |            | December 31,
2001 |          
|----------------------------------------------- | ------------------------------------------------------------------------------------------------- | ------------------------------------------ | ---------- | ----------------- | ---------
|
|Liabilities and Shareholder's Equity            |                                                                                                   |                                            |            |                   |          
|Current Liabilities                             |                                                                                                   |                                            |            |                   |          
|                                                | Accounts payableaffiliates                                                                       |                                            | $          | 12,639            |          
|                                                | Accounts payable and accrued liabilities                                                          |                                            |            | 376,471           |          
|                                                | Liabilities under energy trading and price risk management                                        |                                            |            | 31,462            |          
|                                                | Interest payable                                                                                  |                                            |            | 90,794            |          
|                                                | Short-term obligations                                                                            |                                            |            | 53,432            |          
|                                                | Current portion of long-term incentive compensation                                               |                                            |            | 4,038             |          
|                                                | Current maturities of long-term obligations                                                       |                                            |            | 177,086           |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total current liabilities                  |            |                   | 745,922  
|                                                |                                                                                                   |                                            |            |                   |          
|Long-Term Obligations Net of Current Maturities |                                                                                                   |                                            | 5,835,832  |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Long-Term Deferred Liabilities                  |                                                                                                   |                                            |            |                   |          
|                                                | Deferred taxes and tax credits                                                                    |                                            |            | 940,277           |          
|                                                | Deferred revenue                                                                                  |                                            |            | 466,142           |          
|                                                | Long-term incentive compensation                                                                  |                                            |            | 38,094            |          
|                                                | Long-term liabilities under energy trading and price risk management                              |                                            |            | 154,535           |          
|                                                | Other                                                                                             |                                            |            | 249,171           |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total long-term deferred liabilities       |            |                   | 1,848,219
|                                                |                                                                                                   |                                            |            |                   |          
|Liabilities of Discontinued Operations          |                                                                                                   |                                            | 4,069      |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Total Liabilities                               |                                                                                                   |                                            | 8,434,042  |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Minority Interest                               |                                                                                                   |                                            | 406,251    |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Preferred Securities of Subsidiaries            |                                                                                                   |                                            |            |                   |          
|                                                | Company-obligated mandatorily redeemable security of partnership holding solely parent debentures |                                            |            | 150,000           |          
|                                                | Subject to mandatory redemption                                                                   |                                            |            | 122,050           |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total preferred securities of subsidiaries |            |                   | 272,050  
|                                                |                                                                                                   |                                            |            |                   |          
|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                                                                        |                                            |            | 2,633,767         |          
|                                                | Retained deficit                                                                                  |                                            |            | (849,827          | )        
|                                                | Accumulated other comprehensive loss                                                              |                                            |            | (197,833          | )        
|                                                |                                                                                                   |                                            |            |                   |          
|Total Shareholder's Equity                      |                                                                                                   |                                            | 1,650,237  |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Total Liabilities and Shareholder's Equity      |                                                                                                   | $                                          | 10,762,580 |                   | $        
|                                                |                                                                                                   |                                            |            |                   |          

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)

|                                                                        |                                                                                                | Six Months Ended
June 30,                                |         
|----------------------------------------------------------------------- | ---------------------------------------------------------------------------------------------- | -------------------------------------------------------- | --------
|
|
|Cash Flows From Operating Activities                                    |                                                                                                |                                                          |         
|                                                                        | Income (loss) from continuing operations, after accounting change, net                         |                                                          | $       
|                                                                        | Adjustments to reconcile income (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                           |         
|                                                                        |                                                                                                | Gain on sale of assets                                   |         
|                                                                        |                                                                                                | Cumulative effect of change in accounting, net of tax    |         
|                                                                        | Changes in operating assets and liabilities:                                                   |                                                          |         
|                                                                        |                                                                                                | Decrease in accounts receivable                          |         
|                                                                        |                                                                                                | Increase in inventory                                    |         
|                                                                        |                                                                                                | Decrease (increase) in prepaid expenses and other        |         
|                                                                        |                                                                                                | Decrease in accounts payable and accrued liabilities     |         
|                                                                        |                                                                                                | Increase in interest payable                             |         
|                                                                        |                                                                                                | Increase (decrease) in long-term incentive compensation  |         
|                                                                        |                                                                                                | Decrease (increase) in assets under risk management, net |         
|                                                                        | Other operating, net                                                                           |                                                          |         
|                                                                        |                                                                                                |                                                          |         
|                                                                        |                                                                                                |                                                          | 44,444  
|                                                                        | Operating cash flow from discontinued operations                                               |                                                          |         
|                                                                        |                                                                                                |                                                          |         
|                                                                        |                                                                                                | Net cash provided by (used in) operating activities      |         
|                                                                        |                                                                                                |                                                          |         
|Cash Flows From Financing Activities                                    |                                                                                                |                                                          |         
|                                                                        | Borrowings long-term debt and lease swap agreements                                            |                                                          |         
|                                                                        | Payments on long-term debt agreements                                                          |                                                          |         
|                                                                        | Short-term financing, net                                                                      |                                                          |         
|                                                                        | Cash dividends to parent                                                                       |                                                          |         
|                                                                        | Funds provided to discontinued operations                                                      |                                                          |         
|                                                                        | Issuance of preferred securities                                                               |                                                          |         
|                                                                        |                                                                                                |                                                          |         
|                                                                        |                                                                                                |                                                          | (155,554
|                                                                        | Financing cash flow from discontinued operations                                               |                                                          |         
|                                                                        |                                                                                                |                                                          |         
|                                                                        |                                                                                                | Net cash provided by (used in) financing activities      |         
|                                                                        |                                                                                                |                                                          |         
|Cash Flows From Investing Activities                                    |                                                                                                |                                                          |         
|                                                                        | Investments in and loans to energy projects                                                    |                                                          |         
|                                                                        | Purchase of common stock of acquired companies                                                 |                                                          |         
|                                                                        | Purchase of power sales agreement                                                              |                                                          |         
|                                                                        | Capital expenditures                                                                           |                                                          |         
|                                                                        | Proceeds from return of capital and loan repayments                                            |                                                          |         
|                                                                        | Proceeds from sale of interest in projects                                                     |                                                          |         
|                                                                        | Proceeds from sale of assets                                                                   |                                                          |         
|                                                                        | Decrease in restricted cash                                                                    |                                                          |         
|                                                                        | Investments in other assets                                                                    |                                                          |         
|                                                                        | Other, net                                                                                     |                                                          |         
|                                                                        |                                                                                                |                                                          |         
|                                                                        |                                                                                                |                                                          | (36,206 
|                                                                        | Investing cash flow from discontinued operations                                               |                                                          |         
|                                                                        |                                                                                                |                                                          |         
|                                                                        |                                                                                                | Net cash used in investing activities                    |         
|                                                                        |                                                                                                |                                                          |         
|Effect of exchange rate changes on cash                                 |                                                                                                |                                                          | 27,308  
|                                                                        |                                                                                                |                                                          |         
|Net decrease in cash and cash equivalents                               |                                                                                                |                                                          | (84,223 
|Cash and cash equivalents at beginning of period                        |                                                                                                |                                                          | 434,249 
|                                                                        |                                                                                                |                                                          |         
|Cash and cash equivalents at end of period                              |                                                                                                |                                                          | 350,026 
|Cash and cash equivalents classified as part of discontinued operations |                                                                                                |                                                          | (6,563  
|                                                                        |                                                                                                |                                                          |         
|Cash and cash equivalents of continuing operations                      |                                                                                                | $                                                        | 343,463 
|                                                                        |                                                                                                |                                                          |         

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    JUNE 30, 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 six months ended June 30, 2002 are not necessarily indicative of the operating results for the full year.

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

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

Industry Developments

A number of significant recent developments have adversely affected not only those companies primarily focused on the trading of electricity but also those
independent power producers who sell a sizable portion of their generation, not pursuant to long-term contracts, but rather into the wholesale
energy market. Often referred to as merchant generators, the financial performance of these companies has been affected by one or more of the following:



As
a result, many merchant generators and power trading firms have announced plans to improve their financial position through asset sales, the cancellation or deferral of substantial
new development, decreases in capital expenditures, reductions in operating costs and the issuance of equity.

Our Situation

Because of the 2000-2001 California power crisis, and its indirect effect on us, we began in early 2001 to shift our emphasis from the development and
acquisition of projects to focus instead on enhancing the performance of our existing projects and on maintaining credit quality. As a result, during 2001 and early 2002, we completed the sale of
several non-strategic project investments, and,

6

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during the first quarter of 2002, further reduced business development activities and undertook a related effort to reduce both corporate overhead and other expenditures across the organization and
reduce debt.

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

Our
Illinois Plants have been largely unaffected by these developments this year, because Exelon Generation is under contract to buy substantially all of the capacity of these units for
the balance of 2002. However, as permitted by the contracts governing our coal-fired units in Illinois, Exelon has advised us that they will not exercise their right to purchase 2,684
megawatts (MW) of the capacity of these units for 2003 and 2004. As a result, beginning in 2003, the portion of our generation to be sold into the wholesale markets will significantly increase,
thereby increasing our merchant risk. See "Management's Discussion and Analysis of Results of Operations and Financial ConditionMarket RisksIllinois Plants."

In
addition, our credit rating and the credit ratings of some of our major subsidiaries are under review for possible downgrade below investment grade by Moody's and Standard & Poor's
due to industry developments, lower wholesale energy prices and the increase in our merchant risk beginning in 2003 as described above. See "Management's Discussion and Analysis of Results of
Operations and Financial ConditionCredit Ratings."

Against
this background, we have:



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

7

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NOTE 2. INVENTORY

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

June 30,
2002

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

$
127.7

$
110.1Spare parts, materials and supplies


59.6


57.3Total

$
187.3

$
167.4


NOTE 3. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

|                                     |  | Currency
Translation
Adjustments |        | Unrealized Gains
(Losses) on Cash
Flow Hedges |   | Accumulated Other
Comprehensive
Income (Loss) |  
|------------------------------------ |  | -------------------------------- | ------ | --------------------------------------------- | - | --------------------------------------------- | -
|Balance at December 31, 2001         |  | $                                | (133.4 | )                                             | $ | (168.4                                        | )
|Current period change                |  |                                  | 79.3   |                                               |   | 24.7                                          |  
|                                     |  |                                  |        |                                               |   |                                               |  
|Balance at June 30, 2002 (Unaudited) |  | $                                | (54.1  | )                                             | $ | (143.7                                        | )
|                                     |  |                                  |        |                                               |   |                                               |  

Unrealized
gains (losses) on cash flow hedges included those related to the hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy
Yang B project in Australia. This contract does not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. Approximately
60% of our accumulated other comprehensive loss at June 30, 2002 related to net unrealized losses on the cash flow hedge resulting from this contract. These losses arise because current
forecasts of future electricity prices in these markets are greater than our contract prices. Nevertheless, we believe that these contract prices meet our profit objectives and insulate us from
fluctuations in market prices. Assuming the long-term contract with the State Electricity Commission of Victoria continues to qualify for treatment as a cash flow hedge, future changes in
the forecast of market prices for the contract volumes included in this contract 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 those related to our share of interest rate swaps of our unconsolidated affiliates and the Loy Yang B project.

As
our hedged positions are realized, approximately $4.8 million, after tax, of the net unrealized losses on cash flow hedges at June 30, 2002 are expected to be
reclassified into earnings during the next 12 months. Management expects that when the hedged items are recognized in earnings, the net unrealized losses associated with them will be offset.
The maximum period over which we have designated a cash flow hedge, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is
14 years.

NOTE 4. DISCONTINUED OPERATIONS

On December 21, 2001, Edison First Power Limited completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in
the United Kingdom to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities
associated with the plants. The sale was the result of a competitive bidding process. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion.

8

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

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
June 30, |      | Six Months Ended
June 30, |  
|--------------------------------------------------------------------------------------------- |  | --------------------------- | ---- | ------------------------- | -
|
|
|Total operating revenues                                                                      |  | $                           | (1.0 | )                         | $
|Income (loss) before income taxes                                                             |  |                             | 3.1  |                           |  
|Income (loss) before accounting change                                                        |  |                             | 3.1  |                           |  
|Cumulative effect of change in accounting, net of income tax expense of $2.5 million for 2001 |  |                             |     |                           |  
|Income (loss) from operations of discontinued foreign subsidiary                              |  |                             | 3.1  |                           |  

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

June 30,
2002

December 31,
2001(Unaudited)Cash and cash equivalents

$
6.6

$
62.1Accounts receivabletrade, net of allowance of $1.2 million and $1.4 million in 2002 and 2001, respectively


6.7


88.4Other current assets


0.2


1.5Total current assets


13.5


152.0Other assets





1.6Total long-term assets





1.6Assets of discontinued operations

$
13.5

$
153.6Accounts payable and accrued liabilities

$
4.1

$
51.6Interest payable





4.2Total current liabilities


4.1


55.8Liabilities of discontinued operations

$
4.1

$
55.8


9

---

NOTE 5. RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

Non-Trading Derivative Financial Instruments

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

June 30,
2002

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

$
(24.6
)
$
(35.8
)Interest rate options


(0.2
)

(1.0
)Commodity price:Forwards


50.5


63.8Futures


(0.5
)

(8.4
)Options


0.2


0.4Swaps


(127.8
)

(137.6
)Foreign currency forward exchange agreements


(0.6
)

(0.6
)Cross currency interest rate swaps


3.9


27.6


In
assessing the fair value of our non-trading derivative financial instruments, we use a variety of methods and assumptions based on the market conditions and associated
risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time
value of money, volatility of the underlying commodities and other factors. The following table summarizes the maturities, the valuation method and the related fair value of our risk management assets
and liabilities (as of June 30, 2002) (in millions):

|                                                   |  | Total Fair
Value |       | Maturity
<1 year |   | Maturity
1 to 3
years |  | Maturity
4 to 5
years |      | Maturity
>5 years |  
|-------------------------------------------------- |  | ---------------- | ----- | ---------------- | - | --------------------- |  | --------------------- | ---- | ----------------- | -
|
|Assets:                                            |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Prices actively quoted                             |  | $                | 26.0  |                  | $ | 23.7                  |  | $                     | 2.3  |                   | $
|Prices based on models and other valuation methods |  |                  | 40.3  |                  |   | 14.9                  |  |                       | 22.4 |                   |  
|                                                   |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Total Assets                                       |  | $                | 66.3  |                  | $ | 38.6                  |  | $                     | 24.7 |                   | $
|                                                   |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Liabilities:                                       |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Prices actively quoted                             |  | $                | 10.0  |                  | $ | 7.9                   |  | $                     | 2.1  |                   | $
|Prices based on models and other valuation methods |  |                  | 133.9 |                  |   | 10.2                  |  |                       | 18.3 |                   |  
|                                                   |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Total Liabilities                                  |  | $                | 143.9 |                  | $ | 18.1                  |  | $                     | 20.4 |                   | $
|                                                   |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Grand Total                                        |  | $                | (77.6 | )                | $ | 20.5                  |  | $                     | 4.3  |                   | $
|                                                   |  |                  |       |                  |   |                       |  |                       |      |                   |  

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

Energy Trading Derivative Financial Instruments

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

10

---

related factors, we have minimized our trading activities and our price risk management activities with third parties not related to our power plants or investments in energy projects. See
"Management's Discussion and Analysis of Results of Operations and Financial ConditionIndustry Developments." To the extent we engage in trading activities, we seek to manage price risk
and create stability of future income by selling electricity in the forward markets and, to a lesser degree, to generate profit from price volatility of electricity and fuels by buying and selling
these commodities in wholesale markets. We generally balance forward sales and purchase contracts and manage our exposure through a value at risk analysis as described further below.

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

June 30, 2002

December 31, 2001Assets

Liabilities

Assets

Liabilities(Unaudited)Forward contracts

$
115.5

$
25.8

$
4.6

$
2.9Futures contracts





0.1


0.1


0.1Option contracts


0.8


0.2





Swap agreements


10.5


4.8


0.2


Total

$
126.8

$
30.9

$
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. The following table summarizes the maturities, the valuation method and the related fair value of our energy trading assets and liabilities (as of June 30, 2002) (in millions):

|                                                   |  | Total Fair
Value |       | Maturity
<1 year |   | Maturity
1 to 3
years |  | Maturity
4 to 5
years |     | Maturity
>5 years
|-------------------------------------------------- |  | ---------------- | ----- | ---------------- | - | --------------------- |  | --------------------- | --- | -----------------
|
|Assets:                                            |  |                  |       |                  |   |                       |  |                       |     |                  
|Prices actively quoted                             |  | $                | 13.9  |                  | $ | 13.9                  |  | $                     |    |                  
|Prices based on models and other valuation methods |  |                  | 115.4 |                  |   | 4.3                   |  |                       | 7.7 |                  
|                                                   |  |                  |       |                  |   |                       |  |                       |     |                  
|Total Assets                                       |  | $                | 129.3 |                  | $ | 18.2                  |  | $                     | 7.7 |                  
|                                                   |  |                  |       |                  |   |                       |  |                       |     |                  
|Liabilities:                                       |  |                  |       |                  |   |                       |  |                       |     |                  
|Prices actively quoted                             |  | $                | 11.3  |                  | $ | 11.3                  |  | $                     |    |                  
|Prices based on models and other valuation methods |  |                  | 22.1  |                  |   | 6.9                   |  |                       | 4.3 |                  
|                                                   |  |                  |       |                  |   |                       |  |                       |     |                  
|Total Liabilities                                  |  | $                | 33.4  |                  | $ | 18.2                  |  | $                     | 4.3 |                  
|                                                   |  |                  |       |                  |   |                       |  |                       |     |                  
|Grand Total                                        |  | $                | 95.9  |                  | $ |                      |  | $                     | 3.4 |                  
|                                                   |  |                  |       |                  |   |                       |  |                       |     |                  

11

---

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

Three Months Ended
June 30,

Six Months Ended
June 30,2002

2001

2002

2001(Unaudited)Operating RevenuesForward contracts

$
2.6

$
7.2

$
20.2

$
1.6Futures contracts


(0.4
)

(0.4
)

(0.6
)

(1.9
)Option contracts


(0.1
)

(0.3
)

(0.5
)

2.9Swap agreements


4.4





3.9


(0.2
)Total

$
6.5

$
6.5

$
23.0

$
2.4


The
unrealized gain (loss) from trading and price risk management activities included in the above amounts was $(0.1) million for the three month periods ended June 30, 2002 and
2001, and $11.3 million and $(16.9) million for the six month periods ended June 30, 2002 and 2001, respectively.

NOTE 6. COMMITMENTS AND CONTINGENCIES

Capital Expenditures

The estimated capital expenditures by our subsidiaries for the remainder of 2002 are $98.3 million. We have anticipated that upgrades to environmental
controls at the Illinois Plants to reduce nitrogen oxide emissions would result in expenditures of approximately $317.5 million for the period 2003 - 2005. As a result
of changes in the merchant energy marketplace, we are evaluating our capital expenditure program, including environmental improvements. At June 30, 2002, we have capitalized
$33.5 million as construction in progress related to environmental improvements. We are currently updating our capital expenditure program and evaluating whether to proceed, delay or cancel
individual projects. We expect to complete the update of our capital expenditure program by the end of 2002.

On
August 9, 2002, we exercised our option to purchase the Illinois peaker power units that were subject to a lease with a third-party lessor. As disclosed in
Off-Balance Sheet Transactions in our 2001 Annual Report on Form 10-K, this operating lease was structured to maintain a minimum amount of equity (3% of the acquisition
price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases). This transaction represents
the only synthetic lease that we had outstanding at June 30, 2002. The exercise of the purchase option resulted in the payment of $300 million to the owner-lessor, of which we received
$255 million as repayment of the note receivable held by us. Accordingly, the net cash outlay required to exercise the purchase option was $45 million. See our 2001 Annual Report on
Form 10-K for further information on off-balance sheet transactions.

We
have commitments to purchase three turbines from Siemens Westinghouse for a new gas-fired project. These turbines are planned to be used to meet our additional
gas-fired generation obligation at the Illinois Plants, or for a new development project. The amount capitalized at June 30, 2002 related to these three turbines was
$75.2 million. Due to continued changes in the wholesale energy markets and discussions regarding the additional gas-fired generation obligation at the Illinois Plants (see update
under "Additional Gas-Fired Generation" included in this note), we are evaluating whether to
consummate the purchase of these turbines and maintain them in storage until market conditions improve or cancel the equipment purchase contracts for these turbines. If we cancel the contracts, under
the terms of the purchase contracts, we would be entitled to recover cash amounts paid in excess of 50% of the turbine purchase price, but it would also result in a pre-tax loss of
$60.5 million. We expect to make a decision regarding the plan for these turbines by September 30, 2002.

12

---

Commercial Commitments

The following table summarizes our consolidated commercial commitments as of June 30, 2002. Details regarding these commercial commitments are discussed in
the sections following the table.

|                                                       |  | Amount of Commitments Per Period in U.S.$ |       | 
|------------------------------------------------------ |  | ----------------------------------------- | ----- | 
|
|
|
|Standby letters of credit                              |  | $                                         | 50.6  | 
|Firm commitment for asset purchase                     |  |                                           | 38.0  | 
|Firm commitments to contribute project equity          |  |                                           | 58.8  | 
|Environmental improvements at our project subsidiaries |  |                                           | 33.2  | 
|                                                       |  |                                           |       | 
|Total Commercial Commitments                           |  | $                                         | 180.6 | 
|                                                       |  |                                           |       | 

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 guarantees 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, counterparties to these contracts could request us to provide adequate assurance. Adequate assurance could take the form of supplying
additional financial information, collateral, letters of credit or cash. As of June 30, 2002, the amount of such exposure under counterparty trade agreements was $6.8 million. Failure to
provide adequate assurance could result in a counterparty liquidating an open position and filing a claim against us for any losses.

Our
United Kingdom price risk management activities for our First Hydro project are managed through our subsidiary, Edison Mission Marketing and Services Limited. We currently provide
guarantees by Edison Mission Energy of most of this subsidiary's grid trade master agreements (referred to as GTMAs) with third-party counterparties in order to support the credit of First Hydro. If
we do not maintain an investment grade rating or if other events adversely affect our financial position, counterparties could request us, under the terms of the relevant GTMA, to provide adequate
assurance similar to the description above for domestic activities.

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

13

---

Firm Commitment for Asset Purchase

Project

Local Currency

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

4.9 million Euro

$
4.8Siemens Westinghouse Turbines(ii)



$
38.2


---

Firm Commitments to Contribute Project Equity

Project

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

$
48.5Italian Wind Expansion(ii)

$
2.8Sunrise(iii)

$
74.9


---

14

---

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

Contingencies

Paiton

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

Our
investment in the Paiton project increased to $514.4 million at June 30, 2002 from $492.1 million at December 31, 2001. The increase in the investment
account resulted from our subsidiary recording its proportionate share of net income from Paiton Energy as well as its proportionate share of other comprehensive income. Our investment in the Paiton
project will increase (decrease) from earnings (losses) from Paiton Energy and decrease by cash distributions. Assuming Paiton Energy remains profitable, we expect the investment account to increase
substantially during the next several years as earnings are expected to exceed cash distributions.

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

While
the Binding Term Sheet has been approved by the project lenders, Paiton Energy has not yet obtained approval of the amendment to the power purchase agreement by the project
lenders.

15

---

Paiton Energy and its lenders have initiated negotiations on a restructuring of the senior debt which takes into account the revised payment terms as agreed in the amendment to the power purchase
agreement. 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 our partner from all claims and costs arising from or in connection with the contractor litigation, which
indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. 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 fees, royalty fees, and distributions (if any) from the project. We believe that the outcome of this
litigation will not have a material adverse effect on our consolidated financial position or results of operations.

ISAB

In connection with the financing of the ISAB project, which is located near Siracusa in Sicily, Italy, we have guaranteed for the benefit of the banks financing
the construction of the ISAB project our subsidiary's obligation to contribute project equity and subordinated debt totaling up to approximately $36 million. The amount of payment under the
obligation is contingent upon the outcome of an arbitration proceeding brought in 1999 by the contractor of the project against ISAB Energy. On April 19, 2002, the arbitration tribunal issued a
partial award on liability dismissing 10 of the contractor's 14 claims. The tribunal found there was a legal and factual basis for a "slight extension" of the guaranteed completion date and a "slight
indemnification" of the contractor in relation to the four successful claims. Certain additional minor claims of the contractor, together with ISAB Energy's counterclaims for defects and delay
liquidated damages, are still to be heard by the tribunal on a date to be agreed by the parties or as otherwise directed by the tribunal.

Regulatory Developments Affecting Sunrise Power Company

Sunrise Power Company, in which our wholly-owned subsidiary owns 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 requested that the contracts be abrogated. The California Electricity
Oversight Board complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the alternative, abrogated
as of a future date, to allow for the possibility of renegotiation. After hearings and intermediate rulings, on July 23, 2002, the Federal Energy Regulatory Commission dismissed with prejudice
the California Public Utilities Commission and California Electricity Oversight Board complaints against Sunrise. The California Public Utilities Commission and

16

---

California Energy Oversight Board have a right of appeal to the federal courts of appeal within 60 days of the date of the order.

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

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

Federal Income Taxes

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

Indemnities



Some of our subsidiaries have entered into indemnification agreements, under which the subsidiaries agreed to repay capacity payments to the projects' power
purchasers in the event the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. Obligations under these
indemnification agreements as of June 30, 2002, if
payment were required, would be $223.2 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

17

---

time, entered into guarantees and indemnification agreements with respect to acquisitions made by our subsidiaries. In this regard, we have indemnified the previous owners of the Illinois Plants, the
Homer City facilities and the EcoEléctrica facilities for specified liabilities, including environmental liabilities, incurred as a result of their prior ownership of the plants. We do
not believe these indemnification obligations will have a material impact on us.

Tax Indemnity Agreements

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

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 Commonwealth Edison, Exelon
Generation, and the City of Chicago 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)

36.8 million Euro

$
36.3


---





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

18

---

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
|----------------------- |  | -------- | ------- | ------------ | - | ---------------------- |  | ---------------- | ------- | -----
|
|June 30, 2002           |  |          |         |              |   |                        |  |                  |         |      
|Operating revenues      |  | $        | 409.3   |              | $ | 206.6                  |  | $                | 132.8   |      
|Operating income (loss) |  |          | 63.6    |              |   | 77.3                   |  |                  | 38.0    |      
|Total assets            |  | $        | 4,869.9 |              | $ | 3,468.3                |  | $                | 2,062.0 |      
|June 30, 2001           |  |          |         |              |   |                        |  |                  |         |      
|Operating revenues      |  | $        | 503.3   |              | $ | 96.9                   |  | $                | 122.8   |      
|Operating income (loss) |  |          | 150.1   |              |   | 45.4                   |  |                  | 39.5    |      
|Total assets            |  | $        | 6,724.0 |              | $ | 3,115.2                |  | $                | 4,749.7 |      

|Six Months Ended        |  | Americas |         | Asia Pacific |   | Europe and
Middle East |  | Corporate/
Other |         | Total
|----------------------- |  | -------- | ------- | ------------ | - | ---------------------- |  | ---------------- | ------- | -----
|
|June 30, 2002           |  |          |         |              |   |                        |  |                  |         |      
|Operating revenues      |  | $        | 712.7   |              | $ | 360.8                  |  | $                | 284.9   |      
|Operating income (loss) |  |          | 44.1    |              |   | 132.0                  |  |                  | 89.4    |      
|Total assets            |  | $        | 4,869.9 |              | $ | 3,468.3                |  | $                | 2,062.0 |      
|June 30, 2001           |  |          |         |              |   |                        |  |                  |         |      
|Operating revenues      |  | $        | 912.0   |              | $ | 145.7                  |  | $                | 250.7   |      
|Operating income (loss) |  |          | 224.9   |              |   | 71.0                   |  |                  | 80.9    |      
|Total assets            |  | $        | 6,724.0 |              | $ | 3,115.2                |  | $                | 4,749.7 |      

19

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NOTE 8. INVESTMENTS

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

|                   |  | Three Months Ended
June 30, |       | Six Months Ended
June 30,
|------------------ |  | --------------------------- | ----- | -------------------------
|
|
|Operating revenues |  | $                           | 172.3 |                          
|Operating income   |  |                             | 53.3  |                          
|Net income         |  |                             | 52.9  |                          

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, in which we own 37 percent.

|                   |  | Three Months Ended
June 30, |      | Six Months Ended
June 30,
|------------------ |  | --------------------------- | ---- | -------------------------
|
|
|Operating revenues |  | $                           | 51.6 |                          
|Operating income   |  |                             | 21.8 |                          
|Net income         |  |                             | 17.4 |                          

NOTE 9. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION

Six Months Ended
June 30,2002

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

$
202.2

$
220.5Income taxes (receipts)

$
(196.8
)
$
14.8Cash payments under plant operating leases

$
191.0

$
54.4Details of assets acquiredFair value of assets acquired

$


$
888.2Liabilities assumed





(801.3
)Net cash paid for acquisitions

$


$
86.9


NOTE 10. CHANGES IN ACCOUNTING

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

20

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

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. This implementation guidance became effective on April 1, 2002. The adoption of
this implementation guidance had no impact on our financial statements.

Effective
January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 establishes
accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. The Statement requires that goodwill should be
tested for impairment using a two-step approach. The first step used to identify a potential impairment compares the fair value of a reporting unit to its carrying amount, including
goodwill. If the fair value of the reporting unit is less than its carrying amount, the second step of the impairment test is performed to measure the amount of the impairment loss. The second step of
the impairment test is a comparison of the implied fair value of goodwill to its carrying amount. The impairment loss is equal to the excess carrying amount of the goodwill over the implied fair
value. 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 completed the first step described above for each of the
components of our goodwill. The fair value of the reporting units for the Contact Energy and First Hydro operations were in excess of related book value at January 1, 2002. Accordingly, no
impairment of the goodwill related to these reporting units will be recorded upon adoption of this standard. We concluded that fair value of the reporting unit related to the Citizens Power
acquisition was less than our book value and, accordingly, the goodwill related to this reporting unit is impaired at January 1, 2002. We are in the process of completing the second step of the
impairment test described above, which will be completed by December 31, 2002.

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

|                                            |  | Three Months Ended
June 30, |     | Six Months Ended
June 30,
|------------------------------------------- |  | --------------------------- | --- | -------------------------
|
|
|Reported net income (loss)                  |  | $                           | 3.2 |                          
|Add back: Goodwill amortization, net of tax |  |                             |    |                          
|                                            |  |                             |     |                          
|Adjusted net income (loss)                  |  | $                           | 3.2 |                          
|                                            |  |                             |     |                          

21

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

The following discussion contains forward-looking statements. These statements are based on our current plans and expectations and involve
risks and uncertainties which could cause actual future activities and results of operations to be materially different from those set forth in the forward-looking statements. Unless otherwise
indicated, the information presented in this section is with respect to Edison Mission Energy and our consolidated subsidiaries. Important factors that could cause differences are set forth under
"Credit Ratings" and "Market Risk Exposures" below, and under "Risk Factors" in the Management's Discussion and Analysis of Results of Operations and Financial
Condition included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2001.

The Management's Discussion and Analysis of Results of Operations and Financial Condition of this Form 10-Q discusses material changes in the
results of operations, financial condition and other developments of Edison Mission Energy since December 31, 2001, and as compared to the second quarter and six months ended June 30,
2001. This discussion presumes that the reader has read or has access to Management's
Discussion and Analysis of Results of Operations and Financial Condition included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended
December 31, 2001.

General

We are an independent power producer engaged in the business of owning or leasing and operating electric power generation facilities worldwide. We also conduct
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 June 30, 2002, we owned interests in 28 domestic and 50 international operating power projects with an aggregate generating capacity of 23,905 megawatts (MW), of which our
share was 19,095 MW. At that date, one domestic and four international projects, totaling 714 MW of generating capacity, of which our anticipated share will be approximately 357 MW, were in
construction. At June 30, 2002, we had consolidated assets of $10.8 billion and total shareholder's equity of $1.7 billion.

Industry Developments

A number of significant recent developments have adversely affected not only those companies primarily focused on the trading of electricity but also those
independent power producers who sell a sizable portion of their generation, not pursuant to long-term contracts, but rather into the wholesale energy market. Often referred to as merchant
generators, the financial performance of these companies has been affected by one or more of the following:



22

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As
a result, many merchant generators and power trading firms have announced plans to improve their financial position through asset sales, the cancellation or deferral of substantial
new development, decreases in capital expenditures and reductions in operating costs.

Our Situation

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

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

Our
Illinois Plants have been largely unaffected by these developments this year, because Exelon Generation is under contract to buy substantially all of the capacity of these units for
the balance of 2002. However, as permitted by the contracts governing our coal-fired units in Illinois, Exelon has advised us that they will not exercise their right to purchase 2,684 MW
of the capacity of these units for 2003 and 2004. As a result, beginning in 2003, the portion of our generation to be sold into the wholesale markets will significantly increase, thereby increasing
our merchant risk. See "Market RisksIllinois Plants."

In
addition, our credit rating and the credit ratings of some of our major subsidiaries are under review for possible downgrade below investment grade by Moody's and Standard & Poor's
due to industry developments, lower wholesale energy prices and the increase in our merchant risk beginning in 2003
as described above. See "Management's Discussion and Analysis of Results of Operations and Financial ConditionCredit Ratings."

Against
this background, we have:



In
addition, we continue to review the possibility of further sales of assets, but believe for the reasons discussed in more detail below that current market conditions may inhibit our
ability to obtain

23

---

prices commensurate with our valuation of those investments which we might wish to offer for sale. For a discussion of our current financial condition, see "Liquidity and Capital
Resources."

Disposition of Investments in Energy Projects

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

During
the second quarter of 2002, we completed our evaluation of bids submitted by third parties to purchase our interests in the EcoEléctrica and Brooklyn Navy Yard
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. Based on our assessment that the net present value of future cash flows from these projects were higher than purchase prices offered, we have
decided to maintain our ownership interests and not sell these projects at this time. We continue to discuss the possible sale of our interest in the Gordonsville project, although there is no
assurance that we will be able to do so.

24

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RESULTS OF OPERATIONS

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

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

|                    |                       |  |          | Three Months Ended June 30, |   | Six Months Ended June 30,
|------------------- | --------------------- |  | -------- | --------------------------- | - | -------------------------
|
|
|
|
|Operating revenues: |                       |  |          |                             |   |                          
|                    | Illinois Plants       |  | Americas |                             | $ | 277.8                    
|                    | Homer City facilities |  | Americas |                             |   | 80.5                     
|                    | First Hydro           |  | Europe   |                             |   | 75.1                     
|                    | Big 4 projects(2)     |  | Americas |                             |   | 28.0                     
|                    | Four Star(3)          |  | Americas |                             |   | 7.3                      
|Operating income:   |                       |  |          |                             |   |                          
|                    | Illinois Plants       |  | Americas |                             | $ | 37.5                     
|                    | Homer City facilities |  | Americas |                             |   | (10.9                    
|                    | First Hydro           |  | Europe   |                             |   | 15.2                     
|                    | Big 4 projects(2)     |  | Americas |                             |   | 28.0                     
|                    | Four Star(3)          |  | Americas |                             |   | 7.0                      

---

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.

25

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Americas

|                                                             |                          | Three Months Ended
June 30, |       | Six Months Ended
June 30,
|------------------------------------------------------------ | ------------------------ | --------------------------- | ----- | -------------------------
|
|
|Operating revenues                                           |                          | $                           | 364.1 |                          
|Net gains from energy trading and price risk management      |                          |                             | 4.8   |                          
|Equity in income from investments                            |                          |                             | 40.4  |                          
|                                                             |                          |                             |       |                          
|                                                             | Total operating revenues |                             |       | 409.3                    
|Fuel and plant operations (including plant operating leases) |                          |                             | 307.1 |                          
|Depreciation and amortization                                |                          |                             | 33.2  |                          
|Administrative and general                                   |                          |                             | 5.4   |                          
|                                                             |                          |                             |       |                          
|                                                             | Operating income         |                             | $     | 63.6                     
|                                                             |                          |                             |       |                          

Operating Revenues

Operating revenues decreased $15.6 million and $64.2 million in the second quarter and six months ended June 30, 2002, respectively, compared
to the corresponding periods 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 a collapse of the selective catalytic reduction system ductwork of one of the units at the Homer City facilities, known as Unit
3. The unit was restored to operation on April 4, 2002 and is operating with the 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. As a result of the Unit 3 selective catalytic reduction system ductwork collapse, we reviewed the similar structures on
Units 1 and 2 and determined that as a precaution it would be appropriate to install additional reinforcement in these structures. The additional reinforcement extended the duration of
planned outages for these units, which had been scheduled to end on June 2, 2002. Unit 1 returned to service on June 28, 2002, and Unit 2 returned to service on June 26, 2002.

Electric
power generated at the Illinois Plants is sold under power purchase agreements with Exelon Generation Company. Exelon Generation is obligated to make capacity payments for the
plants under contract and an energy payment for electricity produced by these plants. Our revenues under these power purchase agreements were $274.3 million and $260.5 million for the
three-month periods ended June 30, 2002 and 2001, respectively. This represented 37% and 36% of our consolidated operating revenues in 2002 and 2001, respectively. For the six-month
periods ended June 30, 2002 and 2001, our revenues under these power purchase agreements were $435.5 million and $425.2 million, respectively. This represented 32% of our
consolidated operating revenues for both of these six-month periods. For more information on these power purchase agreements, including Exelon's notice of the amount of capacity and energy
purchases for 2003, see "Market Risk ExposuresIllinois Plants."

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

Net
gains from energy trading activities were $6.5 million for the quarters ended June 30, 2002 and 2001, and $23 million and $2.4 million for the six months
ended June 30, 2002 and 2001, respectively. The increase in net gains from trading activities in the six months ended June 30, 2002 of $21 million, compared to the corresponding
period in 2001, was primarily a result of completing the restructuring of

26

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a power sales agreement with an unaffiliated electric utility during the first quarter of 2002. As part of the transaction, we purchased the power sales agreement held by a third party, modified its
terms and conditions, and entered into a long-term power supply agreement with another party. Although the sale and purchase of power arising from these contracts will occur over their
term, we have recorded net gains of $1.8 million and $18.8 million for the second quarter and six months ended June 30, 2002, attributable to their fair value in accordance with
EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (generally referred to as mark-to-market accounting). See
"Liquidity and Capital ResourcesSubsidiary Financing Plans" for a discussion of the non-recourse debt incurred to finance the purchase of the power sales
agreement.

Total
gains and losses from price risk management activities recorded at fair value under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS No. 133), were $(1.7) million and $7.1 million for the second quarter and none and $30.1 million for the six months ended June 30,
2002 and 2001, respectively. The decrease in gains of $8.8 million and $30.1 million from the second quarter and six months ended June 30, 2002, respectively, compared to the
corresponding periods in 2001, were primarily due to realized and unrealized gains in 2001 for a gas swap purchased to hedge a portion of our gas price risk related to our share of gas production in
Four Star, an oil and gas company in which we have a minority interest and which we account for under the equity method. During the second quarter and six months ended June 30, 2001,
we recorded a gain on these gas swaps of $20.6 million and $38.0 million due to a decrease in gas prices. During the second quarter of 2002, we entered into hedge transactions related to
the gas price risk of our investment in Four Star for 2002 with realized and unrealized gains totaling $0.6 million for the second quarter and six months ended June 30, 2002. In
addition, during the second quarter and six months ended June 30, 2001, we recorded a mark-to-market loss of $13.7 million and $8.2 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 $69.6 million and $125.6 million during the second quarter and six months ended June 30, 2002, respectively, compared to
the same prior year periods. The 2002 decrease was primarily a return to levels consistent with prior years following a period of higher revenues from cogeneration projects due to higher energy
pricing during the six-month period ended June 30, 2001, as well as higher revenues from oil and gas investments due to higher oil and gas prices in the six-month period
ended June 30, 2001.

Operating Expenses

Fuel and plant operations, including plant operating leases, decreased $0.9 million and $7.1 million for the second quarter and six months ended
June 30, 2002, respectively, compared to the corresponding periods of 2001. The 2002 decrease in fuel expense of $9.2 million resulted from lower fuel costs at the Homer City facilities
due to decreased generation during the second quarter of 2002, when the facilities experienced major unplanned outages at Units 1, 2 and 3, as compared to the same period in 2001. In addition, fuel
costs were lower at the Illinois Plants during the second quarter and six months ended June 30, 2002 due to lower fuel costs at the Collins Station as compared to the same period in 2001.

Partially
offsetting the 2002 decrease in fuel expense was an increase in plant operating leases of $18.9 million and $35.5 million during the second quarter and six months
ended June 30, 2002, as compared to the corresponding periods of 2001, resulting primarily from lease costs related to the sale-leaseback commitments for the Homer City facilities.
There were no comparable lease costs for the Homer City facilities during the first half of 2001.

27

---

Depreciation
and amortization expense decreased $6.9 million and $12.1 million for the second quarter and six months ended June 30, 2002, respectively, compared to
the same periods last year. The 2002 decrease resulted from lower depreciation expense at the Homer City facilities due to the sale-leaseback transaction for the Homer City facilities to
third-party lessors in December 2001.

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

Operating Income

Operating income decreased $86.5 million and $180.8 million during the second quarter and six months ended June 30, 2002, respectively,
compared to the corresponding periods of 2001. The 2002 decrease was primarily due to an operating loss of $11 million for the second quarter and $8.5 million for the six months ended
June 30, 2002 from the Homer City facilities resulting from major unplanned outages at Units 1, 2 and 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 system. We have completed a preliminary investigation of the event, and a more in-depth analysis of the root causes of the event is ongoing to determine the extent to
which insurers and/or the contractor will cover the resulting costs of property damage and repair. We may also be entitled to recovery of business interruption losses under one of our insurance
programs, but such determination has not been made or quantified at this time.

Illinois Postretirement Benefits Other Than Pensions

Employees at our Illinois facilities in union-represented positions are covered by collective bargaining agreements that are due to expire December 31,
2005. We are currently discussing with the union-represented employees their employee benefits agreement that expired on June 15, 2002. As described in our 2001 Annual Report on
Form 10-K, we have accounted for postretirement benefits obligations on the basis of a substantive plan under Statement of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." A substantive plan means that we are assuming for accounting purposes that we will provide for postretirement benefits to union-represented
employees following conclusion of negotiations to replace the current benefits agreement, even though we have no legal obligation to do so. If no postretirement benefits are provided, we would treat
this as a plan termination under SFAS No. 106 and record a gain. The negotiations regarding these benefits plans are in progress and we expect to finalize an agreement prior to the end of 2002,
although we cannot provide any assurance that these negotiations will be completed on this schedule.

28

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Asia Pacific

|                                     |                          | Three Months Ended
June 30, |       | Six Months Ended
June 30,
|------------------------------------ | ------------------------ | --------------------------- | ----- | -------------------------
|
|
|Operating revenues                   |                          | $                           | 196.4 |                          
|Net gains from price risk management |                          |                             | 1.3   |                          
|Equity in income from investments    |                          |                             | 8.9   |                          
|                                     |                          |                             |       |                          
|                                     | Total operating revenues |                             |       | 206.6                    
|Fuel and plant operations            |                          |                             | 112.4 |                          
|Depreciation and amortization        |                          |                             | 16.9  |                          
|                                     |                          |                             |       |                          
|                                     | Operating income         |                             | $     | 77.3                     
|                                     |                          |                             |       |                          

Operating Revenues

Operating revenues increased $104.0 million and $198.8 million for the second quarter and six months ended June 30, 2002, respectively,
compared to the corresponding periods of 2001. The 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
gains from price risk management activities recorded at fair value increased $0.7 million and $0.1 million for the second quarter and six months ended June 30,
2002, respectively, compared to the corresponding periods of 2001. The gains 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 $5.0 million and $16.2 million during the second quarter and six months ended June 30, 2002, respectively, compared to
the same prior year periods. The 2002 increase is primarily due to an increase in our share of income from the Paiton project of $21.6 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 six months ended June 30, 2002. Prior
to the execution of the Binding Term Sheet, we assumed the lower end of a range of expected outcomes of negotiations of a revised power purchase agreement, which resulted in no recognition of income
during the six months ended June 30, 2001. Partially offsetting this increase in 2002 was a decrease in equity in earnings of Contact Energy which was accounted for on the equity method of
accounting prior to our acquisition of a controlling interest in the company in June 2001.

Operating Expenses

Fuel and plant operations increased $69.2 million and $139.5 million for the second quarter and six months ended June 30, 2002, respectively,
compared to the corresponding periods of 2001. The increase was primarily due to consolidating Contact Energy operating expenses, effective June 1, 2001.

Depreciation
and amortization expense increased $8.6 million and $14.6 million for the second quarter and six months ended June 30, 2002, respectively, compared to
the corresponding periods of 2001. The increase primarily reflects the consolidation of Contact Energy depreciation and amortization expenses, effective June 1, 2001.

29

---

Operating Income

Operating income increased $31.9 million and $61.0 million during the second quarter and six months ended June 30, 2002, respectively,
compared to the corresponding periods of 2001. The 2002 increase was primarily due to consolidating Contact Energy's results of operations, effective June 1, 2001, increased profitability of
our Loy Yang B and Valley Power Peaker projects from higher energy prices, and higher equity in income from the Paiton project discussed above.

Europe and Middle East(1)

|                                              |                          | Three Months Ended
June 30, |       | Six Months Ended
June 30, |  
|--------------------------------------------- | ------------------------ | --------------------------- | ----- | ------------------------- | -
|
|
|Operating revenues                            |                          | $                           | 127.0 |                           | $
|Net gains (losses) from price risk management |                          |                             | (1.1  | )                         |  
|Equity in income from investments             |                          |                             | 6.9   |                           |  
|                                              |                          |                             |       |                           |  
|                                              | Total operating revenues |                             |       | 132.8                     |  
|Fuel and plant operations                     |                          |                             | 85.4  |                           |  
|Depreciation and amortization                 |                          |                             | 9.4   |                           |  
|                                              |                          |                             |       |                           |  
|                                              | Operating income         |                             | $     | 38.0                      |  
|                                              |                          |                             |       |                           |  

---

Operating Revenues

Operating revenues increased $5.3 million and $10.5 million for the second quarter and six months ended June 30, 2002, respectively, compared
to the corresponding periods of 2001. The 2002 increase resulted primarily from higher electric revenues from the First Hydro plant due to favorable ancillary services revenues, increased generation
and sales of purchased power during the first half of 2002, compared to the same prior year period. On March 27, 2001, the United Kingdom pool pricing system was replaced with a bilateral
physical trading system referred to as the new electricity trading arrangements, generally referred to as NETA. The new electricity trading arrangements are described in further detail under
"Market Risk ExposuresUnited Kingdom." As a result of the bilateral market under the new electricity trading arrangements, First Hydro has entered into purchase and sales
contracts covering greater volumes of power to optimize the timing of generation from First Hydro's pumped storage plants. The First Hydro plant is expected to provide for higher electric revenues
during the winter months.

Net
gains (losses) from price risk management activities decreased $1.1 million and increased $5.1 million for the second quarter and six months ended June 30, 2002,
respectively, compared to the corresponding periods of 2001. The 2002 gains (losses) primarily represent the change in market value of long-term commodity contracts entered into by the
First Hydro plant for the purchase and sale of electricity that were recorded at fair value under SFAS No. 133 with changes in fair value recorded through the income statement, effective
July 1, 2001.

Equity
in income from investments increased $5.8 million and $18.6 million during the second quarter and six months ended June 30, 2002, respectively, compared to
the same prior year periods. The 2002 increase was due to higher profitability of our interest in the ISAB project resulting from

30

---

increased generation and settlement of an insurance claim. During the first half of 2001, we recorded losses from this project.

Operating Expenses

Fuel, including purchased power, and plant operations increased $15.9 million and $31.8 million for the second quarter and six months ended
June 30, 2002, respectively, compared to the corresponding periods 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 decreased $1.5 million and increased $8.5 million during the second quarter and six months ended June 30, 2002,
respectively, compared to the same periods of 2001. The 2002 increase was primarily due to equity in income from investments partially offset by a decline in earnings from the First Hydro project as
discussed above.

Corporate/Other

|                                              |                | Three Months Ended
June 30, |      | Six Months Ended
June 30, |  
|--------------------------------------------- | -------------- | --------------------------- | ---- | ------------------------- | -
|
|
|Revenues:                                     |                |                             |      |                           |  
|Net gains (losses) from price risk management |                | $                           | (1.8 | )                         | $
|Expenses:                                     |                |                             |      |                           |  
|Depreciation and amortization                 |                |                             | 3.6  |                           |  
|Long-term incentive compensation              |                |                             | 2.0  |                           |  
|Administrative and general                    |                |                             | 35.9 |                           |  
|                                              |                |                             |      |                           |  
|                                              | Operating loss |                             | $    | (43.3                     | )
|                                              |                |                             |      |                           |  

Net
gains (losses) from price risk management activities recorded at fair value decreased $2.2 million and $3.1 million for the second quarter and six months ended
June 30, 2002, respectively, compared to the corresponding periods of 2001. The losses primarily resulted from the change in market value of our interest rate swaps with respect to our
$100 million senior notes that did not qualify for hedge accounting under SFAS No. 133, which terminated in June 2002.

31

---



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 and interest earned on deferred payouts. During the second quarter of 2001, an adjustment was made to reflect the decrease in market value of stock equivalent units.

Administrative
and general expenses increased $4.7 million and $11.7 million for the second quarter and six months ended June 30, 2002, respectively, compared to the
corresponding periods of 2001. The increase for the six months ended June 30, 2002 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 to reduce administrative and general operating costs, including reductions in management and
administrative personnel.

We
may be entitled to a refund of property insurance premiums based on loss experience for the policy year June 1, 2001 through May 31, 2002 from a portion of the risk that
is re-insured by a captive insurance subsidiary of Edison International. We expect that a determination will be made during the third quarter of 2002.

Other Income (Expense)

Interest and other income decreased $14.3 million and $15.8 million for the second quarter and six months ended June 30, 2002, respectively,
compared to the corresponding periods of 2001. The 2002 decrease was primarily due to lower interest income and foreign exchange losses from intercompany loans.

Interest
expense decreased $25.9 million and $38.4 million for the second quarter and six months ended June 30, 2002, respectively, compared to the same prior year
periods. The 2002 decrease was due to a combination of the following: a reduction in corporate debt from the proceeds of the sale-leaseback of the Homer City facilities in
December 2001 and lower borrowings combined with lower interest rates on variable rate debt tied to LIBOR.

Provision (Benefit) for Income Taxes

During the six months ended June 30, 2002, we recorded an effective tax provision rate (after deduction of minority interest) of 43% 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 six months of 2001 of 48%. The decrease in the annual
effective rate is primarily due to increased earnings from taxable unconsolidated affiliates (and therefore not included in our consolidated tax provision), partially offset by an expected decrease in
anticipated income from operations in the United Kingdom.

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

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

Minority Interest

Minority interest expense increased $3.7 million and $8.6 million for the second quarter and six months ended June 30, 2002, respectively,
compared to the same prior year periods. The 2002 increase

32

---

was due to accounting for Contact Energy on a consolidated basis, effective June 1, 2001, due to the purchase of additional shares of Contact Energy that increased our ownership interest from
42.6% to a controlling interest of 51.2%.

Discontinued Operations

As a result of the change in the prices of power in the United Kingdom and the anticipated negative impacts of such changes on earnings and cash flow, we offered
for sale through a competitive bidding process the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. On December 21, 2001, we completed the sale
of the power plants to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities
associated with the plants. We acquired the plants in 1999 from
PowerGen UK plc for £1.3 billion. Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related
to the acquisition of the power plants. We recorded an after tax loss during 2001 of $1.1 billion related to the loss on disposal of these assets. In accordance with SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets", the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial
statements.

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

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

Cumulative Effect of Change in Accounting Principle

Accounting for Derivatives and SFAS No. 133

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

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

33

---

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:



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 of approximately $0.5 million and $1.5 million during

34

---

the second quarter of 2002 and 2001, respectively, and a net gain (loss) of approximately $(0.2) million and $1.6 million for the six-month periods 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.

35

---

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2002, we had consolidated cash and cash equivalents of $343.5 million and had available a total of $681.3 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 June 30, 2002, there were no cash advances outstanding under either Tranche and $68.7 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 June 30, 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:

Six Months Ended
June 30,2002

2001(Unaudited)
(in millions)Continuing operations

$
44.4

$
(348.5
)Discontinued operations


35.8


(23.6
)$
80.2

$
(372.1
)


The
higher operating cash flow from continuing operations in the first half of 2002, compared to 2001, reflects higher distributions from energy projects. In March 2002, we
received distributions from our investments in partnerships subsequent to their receipt of payments of past due accounts receivable from Southern California Edison. Lower distributions from energy
projects during 2001 primarily resulted from the delay in payments from the California utilities to our investments in California qualifying facilities. The change in operating cash flow from
continuing operations in the first half of 2002 was also due to the timing of cash payables related to working capital items. Net working capital at June 30, 2002 was $324.1 million
compared to $324.6 million at December 31, 2001.

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

Cash Flows From Financing Activities

Net cash provided by (used in) financing activities:

Six Months Ended
June 30,2002

2001(Unaudited)
(in millions)Continuing operations

$
(155.5
)
$
664.4Discontinued operations





(283.0
)$
(155.5
)
$
381.4


36

---

Cash
used in financing activities from continuing operations during the first half of 2002 consisted of payment of $100 million of senior notes that matured, net payments of
$80 million on our $750 million corporate credit facility, $22 million related to debt service payments of one of our subsidiaries, and payments of $86 million from our
Coal and Capex facility. In addition, a wholly-owned subsidiary borrowed $84 million under a note purchase agreement in January 2002. For further discussion of the note purchase
agreement, see "Subsidiary Financing Plans." We also received $54 million from a swap agreement with a bank related to lease payments with our Homer City facilities. Cash provided
by financing activities from continuing operations during the first half of 2001 consisted of issuances under our corporate credit facilities and $600 million from the issuance of 9.875% senior
notes in April 2001, due in 2011. In addition, dividends totaling $65 million were paid to The Mission Group and ultimately to Edison International, our ultimate parent company. As of
June 30, 2002, we had recourse debt of $1.9 billion, with an additional $4.2 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 during the first half of 2001 was primarily related to the repayment of a loan from Edison Capital, an affiliate.

Cash Flows From Investing Activities

Net cash used in investing activities:

Six Months Ended
June 30,2002

2001(Unaudited)
(in millions)Continuing operations

$
(36.2
)
$
(340.5
)Discontinued operations





(7.0
)$
(36.2
)
$
(347.5
)


Cash
used in investing activities from continuing operations during the first half of 2002 included $80.1 million paid for the purchase of a power sales agreement held by a third
party. We invested $114.9 million in the first half of 2002 in new plant and equipment principally related to the Valley Power Peaker project in Australia, the Illinois Plants, the Homer City
facilities, and payments related to three turbines to Siemens Westinghouse. Also, included in capital expenditures during the first half of 2002 were payments for three turbines purchased under the
Edison Mission Energy Master Turbine Lease with funds from restricted cash of $61.1 million, which reduced our restricted cash. In addition, $25 million of restricted cash was used to
satisfy our obligation related to the termination of the Edison Mission Energy Master Turbine Lease, thereby reducing our restricted cash account. We received proceeds of $44 million from the
sales of our 50% interests in the Commonwealth Atlantic and James River projects and our 30% interest in the Harbor project during the first quarter of 2002. In addition, we received
$78.5 million as a return of capital from the Kern River and Sycamore projects subsequent to their receipt of payments of past due accounts receivable from Southern California Edison during the
first quarter of 2002. Restricted cash totaling $53 million was used to meet our lease payment obligations.

Cash
used in investing activities from continuing operations during the first half of 2001 included cash used by us for equity contributions totaling approximately $135 million
through June 30, 2001 to meet capital calls by partnerships that were owed money by Southern California Edison and Pacific Gas and
Electric, following the failure by those entities to pay amounts due for power sold under those agreements. Southern California Edison repaid all outstanding amounts on March 1, 2002, and
Pacific Gas and Electric is making payments against defaulted amounts on a schedule that should allow for

37

---

payment in full by the end of the first quarter of 2003. Through the first half of 2001, $3.8 million was paid towards the purchase price and $1.5 million in equity contributions for
the Italian Wind projects, $20 million was paid for the purchase of the 50% interest in the CBK project and $59.5 million was paid for the purchase of additional shares in Contact
Energy. In June 2001, we also completed the sale of a 50% interest in the Sunrise project to Texaco for $84 million. We invested $106 million during the first half of 2001 in new
plant equipment principally related to the Homer City facilities and Illinois Plants.

Historical Distributions Received By Edison Mission Energy

The following table is presented as an aid in understanding the cash flow of Edison Mission Energy and its various subsidiary holding companies which depend on
distributions from subsidiaries and affiliates to fund general and administrative costs and interest costs of recourse debt. Distributions for the first six months of each year are not necessarily
indicative of annual distributions due to the seasonal fluctuations in our business. Distributions for the prior two calendar years have been included as Exhibit 99.1 to this quarterly report
on Form 10-Q.

Six Months Ended
June 30,2002

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

$


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





43.7First Hydro Holdings





51.6Holding companies of other consolidated operating projects


4.3


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


82.0


Distributions from Four Star Oil and Gas Company


21.0


40.7Distributions from other non-consolidated operating projects


29.4


14.3Total Distributions

$
136.7

$
150.6


---

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



38

---



Restricted Assets of our Subsidiaries

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



Edison Mission Midwest Holdings is the borrower under a $1.869 billion credit facility with a group of commercial banks. The funds borrowed under this
facility were used to fund the acquisition of the Illinois Plants and provide working capital to such operations. Midwest Generation LLC, a wholly-owned subsidiary of Edison Mission Midwest Holdings
and a separate SEC registrant, owns, leases or operates the Illinois Plants. Midwest Generation entered into sale-leaseback transactions for the Collins Station as part of the original
acquisition and for the Powerton Station and the Joliet Station in August 2000. In order to make a distribution from Edison Mission Midwest Holdings to Edison Mission Energy, Edison Mission
Midwest Holdings and Midwest Generation must be in compliance with the covenants specified in these agreements, including the following financial performance requirements measured on the date of
distribution:



Edison
Mission Midwest Holdings must also maintain a debt service coverage ratio for the prior twelve-month period of at least 1.50 to 1 as long as the power purchase agreements with
Exelon Generation represent 50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenues. If the power purchase agreements with Exelon Generation represent less than 50% of Edison
Mission Midwest Holdings' and its subsidiaries' revenues, it must maintain a debt service coverage ratio of at least 1.75 to 1. Failure to meet such historical debt service coverage ratio is an event
of default under the credit agreement and Collins lease agreements, which, upon a vote by a majority of the lenders to accelerate the due date of the obligations of Edison Mission Midwest Holdings or
associated with the Collins lease, may result in an event of default under the Powerton and Joliet leases.

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

39

---

At
June 30, 2002, we met the historical financial performance measures. However, as a result of lower wholesale energy prices and the possible downgrade of Edison Mission Midwest
Holdings' credit rating, we cannot predict at this time whether we expect to meet the forward looking tests or ratings requirements on distribution dates in the future. If we are unable to meet the
forward looking tests or ratings requirements, we would be unable to receive distributions of cash from Edison Mission Midwest Holdings on the next distribution date (October 1, 2002),
notwithstanding the projected availability of $138 million of cash for distribution on that date.



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



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



A subsidiary of First Hydro Holdings, First Hydro Finance plc, is the borrower of £400 million of Guaranteed Secured Bonds due in 2021. In
order to make a distribution, First Hydro Finance must be in compliance with the covenants specified in its bond indenture, including the following financial performance requirement:



First
Hydro's interest coverage ratio must exceed a minimum default threshold included in the Guaranteed Secured Bonds. When measured for the twelve-month period ended June 30,
2002, First Hydro's interest coverage ratio was above the default threshold but was below the threshold required to permit distributions. We believe that should market and trading conditions
experienced thus far in 2002 be sustained for the balance of the year, First Hydro's interest coverage ratio will also be above the distribution threshold when measured for the twelve-month period
ended December 31, 2002.

40

---

Compliance by First Hydro with these and other requirements of its bond financing documents is subject, however, to market conditions for the sale of energy and ancillary services.



Our subsidiaries, which we refer to as the "Guarantors," that hold our interests in the Big 4 Projects completed a $450 million secured financing in
December 1996. Edison Mission Energy Funding Corp., a special purpose Delaware corporation, issued notes ($260 million) and bonds ($190 million), the net proceeds of which were
lent to the Guarantors in exchange for a note. The Guarantors have pledged their ownership interests in the Big 4 Projects to Edison Mission Energy Funding as collateral for the note. All
distributions receivable by the Guarantors from the Big 4 Projects are deposited into a trust account from which debt service payments are made on the obligations of Edison Mission Energy Funding and
from which distributions may be made to us if Edison Mission Energy Funding is in compliance with the terms of the covenants in its financing documents, including the following requirements measured
on the date of distribution:



The
debt service coverage ratio is determined by the amount of distributions received by the Guarantors from the Big 4 Projects during the relevant quarter divided by the debt service
(principal and interest) on Edison Mission Energy Funding's notes and bonds paid or due in the relevant quarter. At June 30, 2002, there were no restrictions under these covenants on our
ability to receive distributions. Although the credit ratings of Edison Mission Energy Funding's notes and bonds were recently subject to a downgrade to below investment grade, this will have no
effect on the ability of the Guarantors to make distributions to us.

Other Matters Related to Distributions from Subsidiaries or Affiliates

Paiton ProjectPaiton Energy and PT PLN have completed negotiations on an amendment to the power purchase agreement which
incorporates the terms and conditions of the Binding Term Sheet into the power purchase agreement. While the project lenders have approved the Binding Term Sheet, Paiton Energy has yet to obtain
approval of the amendment to the power purchase agreement by the project lenders. Paiton Energy and its lenders have initiated negotiations on a restructuring of the senior debt which takes into
account the revised payment terms as agreed in the amendment to the power purchase agreement. Distributions from the project will not occur until restructuring of the senior debt has been completed,
and in any case, are not likely to commence until at least 2005.

Loy Yang B ProjectDuring 2001, we began construction of a 300 MW gas-fired peaker plant located adjacent to the
Loy Yang B coal-fired power plant site, which we refer to as the Valley Power Peaker project. The peaker units will service peaking demand within the National Energy Market of Eastern
Australia and, specifically, within the State of Victoria by selling the output of the peakers directly into the pool and by entering into financial contracts related to pool prices with other power
generators and distribution businesses. See "Market Risk ExposuresCommodity Price RiskAsia Pacific" for a more detailed description of the pool. We completed the
construction of the peaker plant during the first half of 2002. We financed construction of the project in part through an interim financing which we are in the process of replacing with
long-term financing. Until the long-term financing is completed, we are not permitted to make cash distributions, which we would otherwise have been able to make, from the Loy
Yang B project. We expect that the long-term financing of the project will be completed prior to September 30, 2002.

41

---

Doga ProjectA distribution of approximately $20 million from the Doga Project has been approved by project lenders. We
are in discussions with our minority partner on the most efficient means of making a distribution from this project and expect that this will be completed by the end of 2002.

Lakeland ProjectWith the introduction of the new electricity trading arrangements and the UK government's
so-called Transfer Scheme, the Lakeland power sales agreement and related documents required amendment to be consistent with the procedures under the new trading arrangements and to
implement the separation of the supply and distribution businesses of the counterparty to the power sales agreement mandated by the Transfer Scheme. These amendments require lender approval without
which no distributions are permitted from the project. We are currently seeking approval of agreed amendments and anticipate that the approval process will be completed no later than
October 2002 and that distributions will then be made. As of June 30, 2002, approximately $18 million was otherwise available for distribution.

ISAB ProjectWe own a 49% interest in the ISAB project in Italy. The project has recently renewed its insurance coverage
which, because of the events of September 11, 2001 and the resulting constraints in the insurance industry, is not compliant with the insurance requirements set out in the facility loan
documentation. While we believe the coverage obtained is the maximum available at the current time at reasonable commercial rates, deviations from the specified coverages nevertheless require approval
of the lending group. Additionally, our partner in the project wishes to transfer its ownership of certain of the project-related assets to an affiliate company and is seeking lender approval for
this. Finally, the project is required to provide the lending group periodically with a long-term forecast which is used to determine the loan life coverage ratio based on, among other
things, a set of technical assumptions for the project which must be approved by the technical adviser to the lenders. In part because of the overall group-wide cost analysis being
undertaken by us, preparation of the technical assumptions has been delayed beyond its due date, thereby delaying preparation of the forecast and the calculation of the loan life coverage ratio. We do
not expect to receive distributions from the project until these issues have been resolved with the project's lending group. It is anticipated that these matters will be resolved by
December 31, 2002.

Corporate Financial Ratios

We and our principal bank lenders use two primary financial 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 activities or cash flow
statement data set forth in our Consolidated Statement of Cash Flows. While the ratios included in our corporate credit facilities are designed to 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.

42

---

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

|Financial Ratio                         |  | Covenant                              |  | Actual at
June 30, 2002 |  | Description                                                                                                                                                                            
|--------------------------------------- |  | ------------------------------------- |  | ----------------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Recourse Debt to Recourse Capital Ratio |  | Less than or equal to 67.5%           |  | 62.4%                   |  | Ratio of (a) senior recourse debt to (b) sum of (i) shareholder's equity per our balance sheet adjusted by comprehensive income after December 31, 1999, plus (ii) senior recourse debt
|Interest Coverage Ratio                 |  | Greater than or equal to 1.50 to 1.00 |  | 1.93 to 1.00            |  | For prior 12-month period, ratio of (a) funds flow from operations to (b) interest expense on senior recourse debt                                                                     

---

At
June 30, 2002, we met the above financial covenants. The actual interest coverage ratio during 2001 and the twelve months ended June 30, 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
2.06 to 1 for the twelve months ended June 30, 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 June 30, 2002 was 1.93 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 half of 2002.

43

---

Discussion of Recourse Debt to Recourse Capital Ratio

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

June 30,
2002

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

$
76.7

$
203.6Senior Notes


1,600.0


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


1,442.5


1,431.9Coal and Capex Facility


172.0


251.6Other


45.5


46.3Total Recourse Debt to Edison Mission Energy

$
3,336.7

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

$
2,008.5

$
2,039.0Recourse Capital(3)

$
5,345.2

$
5,672.4Recourse Debt to Recourse Capital Ratio


62.4
%

64.1
%


---

During
the six months ended June 30, 2002, the recourse debt to recourse capital ratio improved due to:



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

44

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Discussion of Interest Coverage Ratio

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

June 30,
2002

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

$
284.7

$
201.3Homer City


101.8


175.2Ferrybridge and Fiddler's Ferry


(57.8
)

(104.5
)First Hydro


50.6


45.9Other consolidated operating projects


64.7


64.1Trading and price risk management


8.8


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


210.9


128.8Distributions from other non-consolidated operating projects


88.8


93.5Interest income


6.4


9.0Operating expenses


(154.3
)

(143.1
)Total funds flow from operations


604.6


498.4Interest Expense:From obligations to unrelated third parties


198.2


188.7From notes payable to Midwest Generation


115.1


116.1Total interest expense


313.3


304.8Interest Coverage Ratio


1.93


1.64


---

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



45

---



Interest
expense increased $8.5 million during the twelve months ended June 30, 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, Moody's and Standard & Poor's downgraded our senior unsecured credit ratings to "Baa3" from "Baa1" and to "BBB-" from "A-,"
respectively. On July 3, 2002, Moody's placed under review for possible downgrade our rating (senior unsecured at Baa3), and the ratings of our parent, Mission Energy Holding Company (senior
secured at Ba2), and our wholly-owned indirect subsidiaries, Edison Mission Midwest Holdings Co. (bank facility at Baa2) and Midwest Generation, LLC (lessor bonds at Baa2). On July 25, 2002,
Standard & Poor's changed its outlook to negative from stable on its "BBB-" corporate credit ratings of Edison Mission Energy, Edison Mission Midwest Holdings Co., and Edison
Mission Marketing and Trading. In addition, Standard & Poor's changed its outlook to negative from stable on its "BBB-" ratings on the lessor bonds of the Homer City lease and the
lessor bonds of the Powerton and Joliet leases. On August 7, 2002, Standard & Poor's lowered its senior unsecured credit rating on Edison Mission Energy Funding Corp. to "BB" from
"BBB-." There is no assurance that Moody's and Standard & Poor's will not downgrade these credit ratings below investment grade.

46

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If
the credit rating of Edison Mission Energy is downgraded below investment grade, Edison Mission Energy could be required to, among other things:



More
generally, a downgrade of Edison Mission Energy's credit ratings below investment grade could increase our cost of capital, increase our credit support obligations, affect our
ability to meet debt service coverage and other financial ratios specified in various financing agreements binding on us and our subsidiaries, 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 Illinois Plants, 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. Finally, changes in forward
market prices and margining requirements could further increase the need for credit support for our trading and risk management activities.

Possible Downgrade of Edison Mission Midwest Holdings

In the event of a downgrade of Edison Mission Midwest Holdings below investment grade, provisions in the agreements binding on Edison Mission Midwest Holdings and
Midwest Generation would limit the ability of Edison Mission Midwest Holdings to use excess cash flow to make distributions to us. The following table summarizes the provisions restricting cash
distributions (sometimes referred to as cash traps) and the related changes in the cost of borrowing by Edison Mission Midwest Holdings under the applicable financing agreements:

|S&P Rating     |  | Moody's Rating |  | Cost of Borrowing
Margin |  | Cash Trap                                                                                    
|-------------- |  | -------------- |  | ------------------------ |  | ---------------------------------------------------------------------------------------------
|
|BBB- or higher |  | Baa3 or higher |  | 150                      |  | No cash trap                                                                                 
|BB+            |  | Ba1            |  | 225                      |  | 50% free cash trapped until six month debt service reserve is funded                         
|BB             |  | Ba2            |  | 275                      |  | 100% of free cash trapped                                                                    
|BB-            |  | Ba3            |  | 325                      |  | 100% of free cash trapped                                                                    
|B+             |  | B1             |  | 325                      |  | 100% cash sweep by lenders to repay debt (excess free cash required to be used to repay debt)

As
part of the sale-leaseback of the Powerton and Joliet power stations, Midwest Generation loaned the proceeds ($1,367 million) to Edison Mission Energy in exchange
for promissory notes in the same aggregate amount. Debt service payments by Edison Mission Energy on the promissory notes are used by Midwest Generation to meet its payment obligations under these
leases. Furthermore, Edison Mission Energy has guaranteed the lease obligations of Midwest Generation under these leases. Edison Mission Energy's obligations under the promissory notes payable to
Midwest Generation are general obligations of Edison Mission Energy and are not contingent upon receiving distributions from Edison Mission Midwest Holdings. See "Historical Distributions
Received by Edison Mission EnergyEdison Mission Midwest Holdings (Illinois Plants)" for a discussion of implications for the Powerton and Joliet leases.

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Possible Downgrade of Edison Mission Marketing & Trading

Pursuant to the Homer City sale-leaseback documents, a downgrade of Edison Mission Marketing & Trading to below investment grade would restrict
the ability of EME Homer City Generation to sell forward the output of the Homer City facilities. Under the sale-leaseback documents, EME Homer City Generation may only engage in permitted
trading activities as defined in the documents. These documents include a requirement that the counterparty to such transactions, and EME Homer City Generation, if acting as seller to an unaffiliated
third party, be investment grade. We currently sell all of the output from the Homer City facilities through Edison Mission Marketing & Trading, and EME Homer City Generation is not rated.
Therefore, in order for us to continue to sell forward the output of the Homer City facilities in the event of a downgrade in Edison Mission Marketing & Trading's credit, either: (1) we
must obtain a waiver from the sale-leaseback owner participant to permit EME Homer City Generation to sell directly into the market or through Edison Mission Marketing & Trading; or
(2) Edison Mission Marketing & Trading must provide assurances of performance consistent with the investment grade requirements of the sale-leaseback documents. We are
permitted to sell the output of the Homer City facilities into the Pennsylvania-New Jersey-Maryland Power Pool (PJM) at any time. See "Market RisksHomer City Facilities."

Corporate 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 June 30, 2002, we had borrowing capacity under this facility of $681.3 million and corporate cash and cash equivalents of
$31.4 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. During the first quarter of 2002, cash flow included distributions from our investments in partnerships made subsequent to their receipt of payments of past due accounts
receivable from Southern California Edison on March 1, 2002. Total amounts paid to these partnerships by Southern California Edison was $415 million, of which our share was
$206.2 million. In addition, we received $211 million in tax-allocation payments from our ultimate parent company, which included $73 million related to the amount due
at December 31, 2001 and $138 million as an estimated tax-allocation payment for 2002. We expect to receive approximately $146 million in tax-allocation
payments during the remainder of 2002. Furthermore, we expect to receive tax-allocation payments during 2003 of approximately $200 million. These and cash distributions from our
subsidiaries represent the major source of cash of Edison Mission Energy to meet its cash requirements. 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. Also see "Historical Distributions Received by Edison Mission EnergyRestricted Assets of Subsidiaries." In addition, the timing and amount of
tax-allocation payments are dependent on the consolidated taxable income of Edison International and its subsidiaries. See "Intercompany Tax-Allocation Payments."

In
addition, we plan to seek a new $300 million to $400 million corporate facility with financial institutions by September 17, 2002, as a replacement of Tranche A
of our existing corporate facility. We understand that a number of merchant energy companies have recently been in discussions with their lenders regarding new credit facilities or extensions to their
existing lines of credit. We also understand that, as a result of market conditions surrounding these companies, they have been either unable to renew, extend or otherwise enter into similar credit
facilities or have entered into new or amended credit facilities with a reduced size, increased cost of borrowing and more restrictive terms. Accordingly, there is no assurance that we will be able to
enter into a new line of credit or, if we are able to enter into a new or extended line of credit, that the amount and the terms would not be

48

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substantially different from those under our current credit facility. Tranche B of our corporate facility ($211.7 million) does not expire until September 17, 2004.

Subsidiary Financing Plans

The estimated capital and construction expenditures of our subsidiaries for the remaining two quarters of 2002 are $98.3 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 $23.3 million in 2002 to fund the estimated capital expenditures of
this project, of which $13.2 million was contributed during the first half of 2002. See "Note 6. Commitments and Contingencies."

On
August 9, 2002, we exercised our option to purchase the Illinois peaker power units that were subject to a lease with a third-party lessor. As disclosed in
"Off-Balance Sheet Transactions" in our 2001 Annual Report on Form 10-K, this lease was structured to maintain a minimum amount of equity (3% of the acquisition price)
for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases). This transaction represents the only
synthetic lease that we had outstanding at June 30, 2002. The exercise of the purchase option resulted in the payment of $300 million to the owner-lessor, of which we received
$255 million as repayment of the note receivable held by us. Accordingly, the net cash outlay required to exercise the purchase option was $45 million. The purchase of these peaker units
will be recorded as an asset and depreciated over their estimated useful life.

Valley Power Peaker Project

During 2001, we began construction of a 300 MW gas-fired peaker plant located adjacent to the Loy Yang B coal-fired power plant site in
Australia, which we refer to as the Valley Power Peaker project. We own a 60% interest in the Valley Power Peaker project, with the remaining interest held by our 51.2% affiliate, Contact Energy. The
peaker units will service peaking demand within the National Energy Market of Eastern Australia and, specifically, within the State of Victoria by selling the output of the peakers directly into the
pool and by entering into financial contracts related to pool prices with other power generators and distribution businesses. We completed the construction of the peaker plant during the first half of
2002. We financed construction of this project in part through an interim financing which we are in the process of replacing with long-term financing. Until the long-term
financing is completed, we are not permitted to make cash distributions, which we would otherwise be able to make, from the Loy Yang B project. We expect that the long-term financing of
the project will be completed prior to September 30, 2002.

Sunrise Project Financing

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

49

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environmental permits. If these uncertainties are resolved, we believe that project financing can be obtained in 2003 which would result in a return of a portion of our equity contribution.

Loan Agreement in Connection with Power Sales Agreement

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

Intercompany Tax-Allocation Payments

We participate in a tax-allocation agreement with other subsidiaries of Edison International. We have historically received tax-allocation
payments related to domestic net operating losses incurred by us. The amount and timing of tax-allocation payments are dependent, in part, on the consolidated taxable income of Edison International
and its subsidiaries and other factors, including specific procedures regarding allocation of state taxes. We are not eligible to receive tax-allocation payments for 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. This occurred in 2002, and, accordingly, we received $211 million in tax-allocation payments from Edison International, which included $73 million related
to the amount due December 31, 2001 and $138 million as an estimated tax-allocation payment for 2002. We expect to receive approximately $146 million in
tax-allocation payments during the remainder of 2002.

Market Risk Exposures

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

Commodity Price Risk

Our energy trading activities and merchant power plants expose us to commodity price risks. Commodity price risks are actively monitored to ensure compliance with
our risk management policies.
Policies are in place which limit the amount of total net exposure we may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with 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.

50

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

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



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

Americas

Illinois Plants

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

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

Under
the power purchase agreement related to our coal-fired generation units, Exelon Generation had the option, exercisable not later than 180 days prior to
January 1, 2003, to retain under

51

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the terms of the agreement for 2003 the capacity of certain option coal units having a capacity of 3,949 MW, with any such capacity not retained being released after January 1, 2003 from the
terms of the agreement. Exelon Generation continues to have a similar option, exercisable not later than 180 days prior to January 1, 2004, to retain or release for 2004 all or a portion
of the option coal units retained for 2003. It remains committed to purchase the capacity of certain committed units having 1,696 MW of capacity for both 2003 and 2004.

In
July 2002, Exelon Generation notified Midwest Generation of its exercise of its option to purchase 1,265 MW of capacity and energy during 2003 (of a possible total of 3,949 MW
subject to option) from the option coal units. As a result, 2,684 MW of capacity of the Will County 1 and 2, Joliet 6 and 7, and Powerton 5 and 6 units will no longer be subject to the power purchase
agreement after January 1, 2003. The notification received from Exelon Generation has no effect on its commitments to purchase capacity from these units for the balance of 2002.

The
following table lists the committed coal units, the units for which Exelon Generation has exercised its call option for 2003, and the units which, as of January 1, 2003, will
be released from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

Coal-Fired Units

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

---

52

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Exelon
Generation also has the option, which it may exercise on or before October 2, 2002, to terminate the power purchase agreements related to the Collins Station and the peaker
plants effective as of January 1, 2003. We are unable to predict whether Exelon will exercise this option as to any of the Collins or peaker units. The exercise of these options will have no
effect on Exelon's commitments to purchase capacity from these units for the remainder of 2002.

In
July 2002, Midwest Generation and Exelon Generation amended the power purchase agreement related to our peaker plants to reinstate, as of July 1, 2002, within the terms
of that agreement four of the oil peaker units at our Fisk Station with a capacity of 160 MW. These units had been released from the terms of that agreement by Exelon Generation's previous exercise of
its options.

The
energy and capacity from any units which do not remain subject to one of the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity,
to be negotiated with customers through a combination of bilateral agreements, forward energy sales and spot market sales. Thus, we will be subject to the market risks related to the price of energy
and capacity described above. We intend to manage this risk, in part, by accessing both the direct customer and over-the-counter markets described below as well as using
derivative financial instruments in accordance with established policies and procedures.

During
2003, the primary markets available to us for electricity sales from the Illinois Plants are expected to be "direct customer" and "over-the-counter."
Direct customer transactions are bilateral sales to regional buyers that principally include investor-owned utilities, municipal utilities, rural electric cooperatives and retail energy suppliers.
Transactions in the direct customer market include real-time, daily and longer term structured sales that meet the specific requirements of wholesale electricity consumers.
Over-the-counter markets are generally accessed through third-party brokers and electronic exchanges, and include forward sales of electricity. The most liquid
over-the-counter markets in the Midwest region are "Into Cinergy," and, to a lesser extent, "Into ComEd."

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

The
following table sets forth the forward month-end market prices for energy per megawatt hour for the calendar 2003 and calendar 2004 "strips" (defined as energy purchases
for the entire calendar year) as publicly quoted for sales "Into ComEd" and "Into Cinergy" during the first six months of 2002. As indicated above, these forward prices will continue to fluctuate as a
result of a number of factors, including gas prices, electricity demand, which is also affected by economic growth, and the

53

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amount of existing and planned power plant capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward market prices.

Into ComEd*

|                  |  | 2003 |       | 2004
|----------------- |  | ---- | ----- | ----
|
|
|January 31, 2002  |  | $    | 27.26 |     
|February 28, 2002 |  |      | 28.96 |     
|March 31, 2002    |  |      | 32.50 |     
|April 30, 2002    |  |      | 32.55 |     
|May 31, 2002      |  |      | 30.85 |     
|June 30, 2002     |  |      | 29.54 |     

Into Cinergy**

|                  |  | 2003 |       | 2004
|----------------- |  | ---- | ----- | ----
|
|
|January 31, 2002  |  | $    | 28.38 |     
|February 28, 2002 |  |      | 30.30 |     
|March 31, 2002    |  |      | 33.82 |     
|April 30, 2002    |  |      | 34.03 |     
|May 31, 2002      |  |      | 31.74 |     
|June 30, 2002     |  |      | 31.08 |     

---

Midwest
Generation intends to hedge a portion of its merchant portfolio risk. To the extent it does not do so, the unhedged portion will be subject to the risks and benefits of
spot-market price movements. The extent to which Midwest Generation will hedge its market price risk through forward over-the-counter sales depends on several
factors. First, Midwest Generation will evaluate over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared to
assuming the risk associated with spot market sales. Second, Midwest Generation's ability to enter into hedging transactions will depend upon Midwest Generation's liquidity and upon the
over-the-counter forward sales markets' having sufficient liquidity to enable Midwest Generation to identify counterparties who are able and willing to enter into hedging
transactions with Midwest Generation. Due to factors beyond Midwest Generation's control, market liquidity has decreased significantly since the beginning of 2002, and a number of formerly significant
trading parties have completely withdrawn from the market or substantially reduced their trading activities. This decrease in market liquidity may require Midwest Generation to rely more heavily on
sales to end user
counterparties in the direct customer markets. Midwest Generation is unable to predict the credit quality that such end user counterparties may have. In the event a counterparty were to default on its
trade obligation, Midwest Generation would be exposed to the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing counterparty were
unable to pay the resulting liquidated damages owed to Midwest Generation. Further, Midwest Generation would be exposed to the risk of non-payment of accounts receivable accrued for
products delivered prior to the time such counterparty defaulted.

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

Midwest
Generation's ability to transmit energy to counterparty delivery points to consummate spot sales and hedging transactions may be affected by transmission constraints. Although
the Federal Energy Regulatory Commission (FERC) and the relevant industry participants are working to minimize such issues, Midwest Generation cannot predict how quickly or how effectively such issues
will be resolved.

A
group of transmission-owning utilities have asked the FERC to permit them to join PJM, and the FERC granted those requests, with conditions, in an order issued on July 31, 2002.
These companies include Commonwealth Edison and American Electric Power. As recently filed by Commonwealth Edison with FERC, Commonwealth Edison will join PJM either as an individual transmission
owner, or as a member of an Independent Transmission Company (ITC). Furthermore, as filed by Commonwealth Edison and approved by FERC, the Commonwealth Edison transmission system, to which the
Illinois Plants are directly interconnected, will be fully integrated into the PJM market structure by the last quarter of 2003. We believe that the integration into the PJM market will allow us to
sell electricity into a well developed, stable, transparent, and liquid cash market without additional transmission charges. The expanded PJM market will be interconnected by numerous
extra-high voltage transmission ties and will include (in addition to the existing market encompassed by PJM) the service territories of Commonwealth Edison, American Electric Power,
Illinois Power, Virginia Power, and Dayton Power and Light. Furthermore, as a condition of approval of the requests to join PJM, the FERC is requiring PJM and its counterpart transmission entity in
the Midwest to form a common, seamless energy market by October 2004, which would further expand the areas into which we may sell power without incurring multiple transmission charges.

Homer City Facilities

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

55

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

24-Hour PJM
Historical Prices*2002

2001January

$
20.52

$
36.66February


20.62


29.53March


24.27


35.05April


25.68


34.58May


21.98


28.64June


24.98


26.61Six-month Average

$
23.01

$
31.85


---

As
shown on the above table, the average historical market prices during the first six months of 2002 are below the average market prices during the first six months of 2001. These
forward prices will continue to fluctuate as a result of a number of factors, including gas prices, electricity demand which is also affected by economic growth, and the amount of existing and planned
power plant capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward market prices. At the end of July 2002, our forecasted yearly
average 24-hour PJM price for 2002 was $25.31, compared to the actual yearly average 24-hour PJM price of $29.07 in 2001. Our forecasted yearly average 24-hour PJM
prices are based on year-to-date actual data and a forecast for the remainder of the year based on current market information.

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

24-Hour PJM
Forward Prices*2003

2004January 31, 2002

$
25.48

$
26.31February 28, 2002


27.11


27.59March 31, 2002


29.69


29.66April 30, 2002


29.19


28.81May 31, 2002


28.40


28.24June 30, 2002


27.96


28.09


---

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

56

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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 (effective July 2, 2002, this time period became 1 hour) before a trading period of one-half hour; a balancing mechanism to
enable the system operator to balance generation and demand and resolve any transmission constraints; a mandatory settlement process for recovering imbalances between contracted and metered volumes
with strong incentives for being in balance; and a Balancing and Settlement Code Panel to oversee governance of the balancing mechanism. The grid operator retains the right under the new market
mechanisms to purchase system reserve and response services to maintain the quality of the electrical supply directly from generators (generally referred to as "ancillary services"). Ancillary
services contracts typically run for a year and can consist of both fixed amounts and variable amounts represented by prices for services that are only paid for when actually called
upon by the grid operator. Physical bilateral contracts have replaced the prior financial contracts for differences, but have a similar commercial function. A key feature of the new arrangements is to
require firm physical delivery, which means that a generator must deliver, and a consumer must take delivery of, its net contracted positions or pay for any energy imbalance at highly volatile
imbalance prices calculated by the market operator. A consequence of this new system has been to increase greatly the motivation of parties to contract in advance and to further develop forwards and
futures markets of greater liquidity than at present. Furthermore, another consequence of the market change is that 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 were adversely affected in
the second half of 2001 by a fall in the differential of the peak daytime energy price compared to the cost of purchasing power at nighttime to pump water back to the top reservoir. Generation
capacity on the U.K. system was 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.

57

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Despite
the foregoing, First Hydro's interest coverage ratio, when measured for the twelve-month period ended June 30, 2002, was above the default threshold in its bond financing
documents, and it was able to make the July 31, 2002 interest payment without recourse to the project's debt service reserve. We believe that should market and trading conditions experienced
thus far in 2002 be sustained for the balance of the year, First Hydro's interest coverage ratio will also be above the default and distribution thresholds when measured for the twelve-month period
ended December 31, 2002. Compliance by First Hydro with these and other requirements of its bond financing documents are subject, however, to market conditions for the sale of energy and
ancillary services. These market conditions are beyond our control.

Asia Pacific

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

New Zealand.A substantial portion of Contact Energy's generation output is hedged by sales to retail electricity customers
and forward contracts with other wholesale electricity counterparties. Contact Energy has entered into forward contracts of varying terms that expire on various dates through March 31, 2007 and
option contracts of varying terms that expire on various dates through October 31, 2002. The New Zealand Government commissioned an inquiry into the electricity industry in
February 2000. Following the inquiry report the New Zealand Government released a Government Policy Statement, at the center of which was a call for the industry to rationalize the three
existing industry codes, form a single governance structure and address transmission pricing methodology. The Government Policy Statement also requested a model use of system agreement be
developed, that is, a framework by which the retailers contract for services from each of the distribution networks, and a consumer complaints ombudsman be established. An essential theme throughout
the Government Policy Statement was the desire that the industry retain a private multilateral self-governing structure. During 2001, an amendment to the Electricity Act of 1992 was passed
that laid out the form that regulation would take if the industry does not heed the Government's call. A draft single governance code was put forward to the New Zealand Commerce Commission for
approval early in 2002. In May 2002, the Commerce Commission passed the draft back to the industry requiring a number of amendments to be made prior to the Commerce Commission giving its
approval. Negotiations between the industry and the Commerce Commission over these amendments are continuing. The new code is likely to be introduced before the end of 2002.

58

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Credit Risks

In conducting our trading and price risk management activities, we contract with a number of utilities, energy companies and financial institutions. To manage
credit risk, we look at the risk of a potential default by our counterparties. Credit risk is measured by the loss we would record if our counterparties failed to perform pursuant to the terms of
their contractual obligations. We have established controls to determine and monitor the creditworthiness of counterparties and use master netting agreements whenever possible to mitigate our exposure
to counterparty risk. We may require counterparties to pledge collateral when deemed necessary. We try to manage the credit in the portfolio based on credit ratings. We use published ratings of
counterparties to guide us in the process of setting credit levels, risk limits and contractual arrangements including master netting agreements. Where external ratings are not available, we conduct
internal assessments of credit risks of counterparties. The credit quality of our counterparties is reviewed regularly by our risk management committee. We also monitor the concentration of credit
risk from various positions, including contractual commitments. Credit concentration is determined on both an individual and group counterparty basis. In addition to continuously monitoring our credit
exposure to our counterparties, we also take appropriate steps to limit exposures, initiate actions to lower credit exposure and take credit reserves if appropriate.

Exelon
Generation accounted for 36% and 42% of our consolidated operating revenues in 2001 and 2000, respectively. We expect Exelon Generation to represent a similar amount of our
consolidated revenues in 2002. Any failure of Exelon Generation to make payments under the power purchase agreements could adversely affect our results of operations and financial condition.

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 $19.6 million and $8.4 million of additional interest expense for the six months ended June 30, 2002 and 2001, respectively, as a result of interest rate
hedging mechanisms. We have entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt.

We
had short-term obligations of $53.4 million at June 30, 2002, consisting of borrowings under a construction facility for the Valley Power Peaker project and
a floating rate loan related to Contact Energy. The fair values of these obligations approximated their carrying values at June 30, 2002, and would not have been materially affected by changes
in market interest rates. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of our total long-term
obligations (including current portion) was $6.0 billion at June 30, 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 provide assurances, however, that fluctuations in exchange rates will be fully offset
by hedges or that currency movements and the

59

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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 six months of 2002, foreign currencies in the U.K., Australia and New Zealand increased in value compared to the U.S. dollar by 4.8%, 10.1% and 17.4%, respectively
(determined by the change in the exchange rates from December 31, 2001 to June 30, 2002). The increase in value of these currencies was the primary reason for the foreign currency
translation gain of $79.3 million during the first six months of 2002.

Contact
Energy enters into foreign currency forward exchange contracts to hedge identifiable foreign currency commitments associated with transactions in the ordinary course of business.
The contracts are primarily in Australian and U.S. dollars with varying maturities through December 2002. At June 30, 2002, the outstanding notional amount of the contracts totaled
$39.1 million and the fair value of the contracts totaled $(0.6) million. During the first six months of 2002, Contact Energy recognized a foreign exchange gain of $0.1 million related
to the contracts that matured during the period.

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

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

Non-Trading Derivative Financial Instruments

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

June 30,
2002

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

$
(24.6
)
$
(35.8
)Interest rate options


(0.2
)

(1.0
)Commodity price:Forwards


50.5


63.8Futures


(0.5
)

(8.4
)Options


0.2


0.4Swaps


(127.8
)

(137.6
)Foreign currency forward exchange agreements


(0.6
)

(0.6
)Cross currency interest rate swaps


3.9


27.6


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

60

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value of money, volatility of the underlying commodities and other factors. The following table summarizes the maturities, the valuation method and the related fair value of our risk management
assets and liabilities (as of June 30, 2002) (in millions):

|                                                   |  | Total Fair
Value |       | Maturity
<1 year |   | Maturity
1 to 3
years |  | Maturity
4 to 5
years |      | Maturity
>5 years |  
|-------------------------------------------------- |  | ---------------- | ----- | ---------------- | - | --------------------- |  | --------------------- | ---- | ----------------- | -
|
|Assets:                                            |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Prices actively quoted                             |  | $                | 26.0  |                  | $ | 23.7                  |  | $                     | 2.3  |                   | $
|Prices based on models and other valuation methods |  |                  | 40.3  |                  |   | 14.9                  |  |                       | 22.4 |                   |  
|                                                   |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Total Assets                                       |  | $                | 66.3  |                  | $ | 38.6                  |  | $                     | 24.7 |                   | $
|                                                   |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Liabilities:                                       |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Prices actively quoted                             |  | $                | 10.0  |                  | $ | 7.9                   |  | $                     | 2.1  |                   | $
|Prices based on models and other valuation methods |  |                  | 133.9 |                  |   | 10.2                  |  |                       | 18.3 |                   |  
|                                                   |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Total Liabilities                                  |  | $                | 143.9 |                  | $ | 18.1                  |  | $                     | 20.4 |                   | $
|                                                   |  |                  |       |                  |   |                       |  |                       |      |                   |  
|Grand Total                                        |  | $                | (77.6 | )                | $ | 20.5                  |  | $                     | 4.3  |                   | $
|                                                   |  |                  |       |                  |   |                       |  |                       |      |                   |  

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

Energy Trading Derivative Financial Instruments

On September 1, 2000, we acquired the trading operations of Citizens Power LLC and, subsequently, combined them with our trading and risk management
operations, now conducted by our subsidiary, Edison Mission Marketing & Trading, Inc. As a result of a number of industry and credit related factors, we have minimized our trading
activities and our price risk management activities with third parties not related to our power plants or investments in energy projects. See "Industry Developments." To the extent we
engage in trading activities, we seek to manage price risk and create stability of future income by selling electricity in the forward markets and, to a lesser degree, to generate profit from price
volatility of electricity and fuels by buying and selling these commodities in wholesale markets. We generally balance forward sales and purchase contracts and manage our exposure through a value at
risk analysis as described further below.

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

|                  |  | June 30, 2002 |       | December 31, 2001
|----------------- |  | ------------- | ----- | -----------------
|
|
|Forward contracts |  | $             | 115.5 |                  
|Futures contracts |  |               |      |                  
|Option contracts  |  |               | 0.8   |                  
|Swap agreements   |  |               | 10.5  |                  
|                  |  |               |       |                  
|Total             |  | $             | 126.8 |                  
|                  |  |               |       |                  

Quoted
market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated
electric utility that

61

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we purchased and restructured and a long-term power supply agreement with another unaffiliated party. We recorded these agreements at fair value based upon a discounting of future
electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of the power supply
agreement. The following table summarizes
the maturities, the valuation method and the related fair value of our energy trading assets and liabilities (as of June 30, 2002) (in millions):

|                                                   |  | Total Fair
Value |       | Maturity
<1 year |   | Maturity
1 to 3
years |  | Maturity
4 to 5
years |     | Maturity
>5 years
|-------------------------------------------------- |  | ---------------- | ----- | ---------------- | - | --------------------- |  | --------------------- | --- | -----------------
|
|Assets:                                            |  |                  |       |                  |   |                       |  |                       |     |                  
|Prices actively quoted                             |  | $                | 13.9  |                  | $ | 13.9                  |  | $                     |    |                  
|Prices based on models and other valuation methods |  |                  | 115.4 |                  |   | 4.3                   |  |                       | 7.7 |                  
|                                                   |  |                  |       |                  |   |                       |  |                       |     |                  
|Total Assets                                       |  | $                | 129.3 |                  | $ | 18.2                  |  | $                     | 7.7 |                  
|                                                   |  |                  |       |                  |   |                       |  |                       |     |                  
|Liabilities:                                       |  |                  |       |                  |   |                       |  |                       |     |                  
|Prices actively quoted                             |  | $                | 11.3  |                  | $ | 11.3                  |  | $                     |    |                  
|Prices based on models and other valuation methods |  |                  | 22.1  |                  |   | 6.9                   |  |                       | 4.3 |                  
|                                                   |  |                  |       |                  |   |                       |  |                       |     |                  
|Total Liabilities                                  |  | $                | 33.4  |                  | $ | 18.2                  |  | $                     | 4.3 |                  
|                                                   |  |                  |       |                  |   |                       |  |                       |     |                  
|Grand Total                                        |  | $                | 95.9  |                  | $ |                      |  | $                     | 3.4 |                  
|                                                   |  |                  |       |                  |   |                       |  |                       |     |                  

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

|                   |  | Three Months Ended
June 30, |      | Six Months Ended
June 30, |  
|------------------ |  | --------------------------- | ---- | ------------------------- | -
|
|
|Operating Revenues |  |                             |      |                           |  
|Forward contracts  |  | $                           | 2.6  |                           | $
|Futures contracts  |  |                             | (0.4 | )                         |  
|Option contracts   |  |                             | (0.1 | )                         |  
|Swap agreements    |  |                             | 4.4  |                           |  
|                   |  |                             |      |                           |  
|Total              |  | $                           | 6.5  |                           | $
|                   |  |                             |      |                           |  

The
unrealized gain (loss) from energy trading activities included in the above amounts was $(0.1) million for the three month periods ended June 30, 2002 and 2001, and
$11.3 million and $(16.9) million for the six month periods ended June 30, 2002 and 2001, respectively.

Off-Balance Sheet Transactions

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

Purchase of Equipment Under Lease

On August 9, 2002, we exercised our option to purchase the Illinois peaker power units that were subject to a lease with a third-party lessor. As disclosed
in "Off-Balance Sheet Transactions" in our 2001 Annual Report on Form 10-K, this lease was structured to maintain a minimum amount of equity (3% of the acquisition
price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases). This transaction

62

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represents the only synthetic lease that we had outstanding at June 30, 2002. The exercise of the purchase option resulted in the payment of $300 million to the owner-lessor, of which
we received $255 million as repayment of the note receivable held by us. Accordingly, the net cash outlay required to exercise the purchase option was $45 million. The purchase of these
peaker units will be recorded as an asset and depreciated over their estimated useful life. The annual increase to depreciation expense will be approximately $20 million.

Environmental Matters and Regulations

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

We
have anticipated that upgrades to environmental controls at the Illinois Plants to reduce nitrogen oxide emissions would result in expenditures of approximately $317.5 million
for the period 2003 - 2005. As a result of changes in the merchant energy marketplace, we are evaluating our capital expenditure program, including environmental
improvements. At June 30, 2002, we have capitalized $33.5 million as construction in progress related to environmental improvements. We are currently updating our capital expenditure
program and evaluating whether to proceed, delay or cancel individual projects. We expect to complete the update of our capital expenditure program by the end of 2002.

Critical Accounting Policies

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

New Accounting Standards

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

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. This implementation guidance became effective on April 1, 2002. The adoption of
this implementation guidance had no impact on our financial statements.

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

63

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requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. The Statement requires that goodwill should be tested for impairment using a
two-step approach. The first step used to identify a potential impairment compares the fair value of a reporting unit to its carrying amount, including goodwill. If the fair value of the
reporting unit is less than its carrying amount, the second step of the impairment test is performed to measure the amount of the impairment loss. The second step of the impairment test is a
comparison of the implied fair value of goodwill to its carrying amount. The impairment loss is equal to the excess carrying amount of the goodwill over the implied fair value. 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 completed the first step described above for each of the components of our goodwill. The fair
value of the reporting units for the Contact Energy and First Hydro operations were in excess of related book value at January 1, 2002. Accordingly, no impairment of the goodwill related to
these reporting units will be recorded upon adoption of this standard. We concluded that fair value of the reporting unit related to the Citizens Power acquisition was less than our book value and,
accordingly, the goodwill related to this reporting unit is impaired at January 1, 2002. We are in the process of completing the second step of the impairment test described above, which will
be completed by December 31, 2002.

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

|                                            |  | Three Months Ended
June 30, |     | Six Months Ended
June 30,
|------------------------------------------- |  | --------------------------- | --- | -------------------------
|
|
|Reported net income (loss)                  |  | $                           | 3.2 |                          
|Add back: Goodwill amortization, net of tax |  |                             |    |                          
|                                            |  |                             |     |                          
|Adjusted net income (loss)                  |  | $                           | 3.2 |                          
|                                            |  |                             |     |                          

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 59 of Edison Mission Energy's Annual Report on
Form 10-K for the fiscal year ended December 31, 2001. Refer to "Market Risk Exposures" in Item 2 for an update to that disclosure.

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PART IIOTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Sunrise Proceedings

Sunrise Power Company, in which our wholly-owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources under a
power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints
with the Federal Energy Regulatory Commission against all sellers of long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California
Public Utilities Commission complaint alleged that the contracts are "unjust and unreasonable" on price and other terms, and requests that the contracts be abrogated. The California Electricity
Oversight Board complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the alternative, abrogated
as of a future date, to allow for the possibility of renegotiation. After hearings and intermediate rulings, on July 23, 2002, the Federal Energy Regulatory Commission dismissed with prejudice
the California Public Utilities Commission and California Electricity Oversight Board complaints against Sunrise. The California Public Utilities Commission and California Energy Oversight Board have
a right of appeal to the federal courts of appeal within 60 days of the date of the order.

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

On
May 15, 2002, Sunrise was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco by James M. Millar, "individually,
and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including Sunrise. The
lawsuit alleges that the defendants, including Sunrise, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain unfair contract terms.
The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies obtained by the defendants.
Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits. The defendants in the Millar
lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California, and filed a motion to stay all proceedings pending final resolution of the
jurisdictional issue. Various plaintiffs have filed pleadings opposing the removal and requesting that the matters be remanded to state court. The motions are still pending.

PMNC Litigation

In February 1997, a civil action was commenced in the Superior Court of the State of California, Orange County, entitled The Parsons Corporation and PMNC
v. Brooklyn Navy Yard Cogeneration Partners, L.P., Mission Energy New York, Inc. and B-41 Associates, L.P., Case No. 774980, in which the plaintiffs asserted general monetary
claims under the construction turnkey agreement for the project in the amount of $136.8 million. Brooklyn Navy Yard has also filed an action entitled Brooklyn Navy Yard Cogeneration Partners,
L.P. v. PMNC, Parsons Main of New York, Inc., Nab Construction Corporation,

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L.K. Comstock & Co., Inc. and The Parsons Corporation, in the Supreme Court of the State of New York, Kings County, Index No. 5966/97 asserting general monetary claims in excess
of $13 million under the construction turnkey agreement. On March 26, 1998, the Superior Court in the California action granted PMNC's motion for attachment in the amount of
$43 million against Brooklyn Navy Yard and attached a Brooklyn Navy Yard bank account in the amount of $0.5 million. Brooklyn Navy Yard is appealing the attachment order. On the same
day, the court stayed all proceedings in the California action pending the New York action. PMNC's motion to dismiss the New York action was denied by the New York Supreme Court and further denied on
appeal in September 1998. On March 9, 1999, Brooklyn Navy Yard filed a motion for partial summary judgment in the New York action. The motion was denied and Brooklyn Navy Yard has
appealed. The appeal and the commencement of discovery were suspended until June 2000 to allow for voluntary mediation between the parties. The mediation ended unsuccessfully on
March 23, 2000. On November 13, 2000, a New York appellate court issued a ruling granting summary judgment in favor of Brooklyn Navy Yard, striking PMNC's cause of action for quantum
meruit, and limiting PMNC to its claims under the construction contract. On February 14, 2002, PMNC moved to amend the complaint in the New York action to add us as a defendant and to seek a
$43 million attachment against us. This motion was heard on May 10, 2002, and the court issued an order denying the motion on June 21, 2002. On August 2, 2002, the court
ordered that discovery be completed by mid-August 2002 and that the parties file dispositive motions on or before September 20, 2002. After ruling on the dispositive motions,
the court plans to set a trial date. We agreed to indemnify Brooklyn Navy Yard and our partner in the venture from all claims and costs arising from or in connection with this litigation.

Paiton Labor Suit

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

BHP Fuel Supply Agreement Arbitration

PT Batu Hitam Perkasa (BHP), one of our partners in Paiton Energy, has informed Paiton Energy that it intends to reactivate a pending arbitration to resolve
disputes under the fuel supply agreement between BHP and Paiton Energy. The arbitration has been stayed since 1999 to allow the parties to engage in settlement discussions to restructure the coal
supply chain for the Paiton project. These discussions did not result in a settlement of all potential claims with respect to the restructuring of the coal supply chain, and BHP recently requested
that the arbitration tribunal permit BHP to amend or supplement its statement of claims to assert additional claims against Paiton Energy for breach, and termination, of the fuel supply agreement. BHP
has not specified the amount of damages, or other relief, it seeks to recover. Paiton Energy intends to contest the arbitration.

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

(a)  Exhibits

Exhibit No.

Description4.16

Participation Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P., Homer City OL1 LLC, as Facility Lessor and Ground Lessee, Wells Fargo Bank Northwest National Association, General Electric
Capital Corporation, The Bank of New York as the Security Agent, The Bank of New York as Lease Indenture Trustee, Homer City Funding LLC and The Bank of New York as Bondholder Trustee, incorporated by reference to Exhibit 4.4 to the EME Homer City
Generation L.P. Form 10-K for the year ended December 31, 2001.4.16.1

Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.16 hereto, incorporated by reference to Exhibit 4.4.1 to the EME Homer City Generation L.P. Form 10-K for the year
ended December 31, 2001.4.17

Open-End Mortgage, Security Agreement and Assignment of Rents, dated as of December 7, 2001, among Homer City OL1 LLC, as the Owner Lessor to The Bank of New York, as Security Agent and Mortgagee, incorporated by
reference to Exhibit 4.9 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.10.10.1

Amendment to Power Purchase Agreement between P.T. Paiton Energy (formerly known as P.T. Paiton Energy Company) as Seller and P.T. PLN (Persero) (as successor to Perusahaan Umum Listrik Negara) as Buyer, dated as of June
28, 2002.10.58.2

Amended and Restated Security Deposit Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P. and The Bank of New York as Collateral Agent, incorporated by reference to Exhibit 10.18.2 to the EME
Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.10.102

Executive Grantor Trust Agreement, incorporated by reference to Exhibit 10.12 to the Edison International Form 10-K for the year ended December 31, 1995. (File No. 1-9936).10.102.1

Executive Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002, incorporated by reference to Exhibit 10.3 to the Edison International Form 10-Q for the quarter ended June 30, 2002. (File No. 1-9936).10.103

Director Grantor Trust Agreement, incorporated by reference to Exhibit 10.10 to the Edison International Form 10-K for the year ended December 31, 1995. (File No. 1-9936).10.103.1

Director Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002, incorporated by reference to Exhibit 10.4 to the Edison International Form 10-Q for the quarter ended June 30, 2002. (File No. 1-9936).99.1

Edison Mission Energy Distribution Summary for the years ended December 31, 2001 and 2000.


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99.2

Homer City Facilities Funds Flow From Operations for the twelve months ended June 30, 2002.99.3

Homer City Facilities Funds Flow From Operations for the twelve months ended December 31, 2001.99.4

Illinois Plants Funds Flow From Operations for the twelve months ended June 30, 2002.99.5

Illinois Plants Funds Flow From Operations for the twelve months ended December 31, 2001.99.6

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


(b)  Reports on Form 8-K

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

Date of Report

Date Filed

Item(s) ReportedMay 10, 2002

May 16, 2002

4, 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)
| |  | ---------------------------------
| |  | By:                              
| |  | Date:                            

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