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SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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Form 10-Q

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

For the quarterly period ended June 30, 2001

or

|/ / | 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 1-13434

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

California(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)


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

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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 /x/  No / /

Number
of shares outstanding of the registrant's Common Stock as of August 13, 2001: 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 Financial Condition and Results of Operations |  | 18  
|3.                           |  | Quantitative and Qualitative Disclosures About Market Risk                            |  | 48  
|PART IIOther Information   
|6.                           |  | Exhibits and Reports on Form 8-K                                                      |  | 49  
|                             |  | Signatures                                                                            |  | 50  

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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                                                |                             | $                            | 677,347                   |  
|                                                                                                 | Equity in income from energy projects                            |                             |                              | 104,871                   |  
|                                                                                                 | Equity in income from oil and gas investments                    |                             |                              | 10,063                    |  
|                                                                                                 | Net gains (losses) from energy trading and price risk management |                             |                              | 10,798                    |  
|                                                                                                 | Operation and maintenance services                               |                             |                              | 12,589                    |  
|                                                                                                 |                                                                  |                             |                              |                           |  
|                                                                                                 |                                                                  |                             | Total operating revenues     |                           |  
|                                                                                                 |                                                                  |                             |                              |                           |  
|Operating Expenses                                                                               |                                                                  |                             |                              |                           |  
|                                                                                                 | Fuel                                                             |                             |                              | 278,020                   |  
|                                                                                                 | Plant operations                                                 |                             |                              | 246,793                   |  
|                                                                                                 | Operation and maintenance services                               |                             |                              | 6,101                     |  
|                                                                                                 | Depreciation and amortization                                    |                             |                              | 88,709                    |  
|                                                                                                 | Long-term incentive compensation                                 |                             |                              | 823                       |  
|                                                                                                 | Administrative and general                                       |                             |                              | 38,456                    |  
|                                                                                                 |                                                                  |                             |                              |                           |  
|                                                                                                 |                                                                  |                             | Total operating expenses     |                           |  
|                                                                                                 |                                                                  |                             |                              |                           |  
|                                                                                                 | Operating income                                                 |                             |                              | 156,766                   |  
|                                                                                                 |                                                                  |                             |                              |                           |  
|Other Income (Expense)                                                                           |                                                                  |                             |                              |                           |  
|                                                                                                 | Interest and other income                                        |                             |                              | 16,251                    |  
|                                                                                                 | Gain on sale of assets                                           |                             |                              | 3,644                     |  
|                                                                                                 | Interest expense                                                 |                             |                              | (162,639                  | )
|                                                                                                 | Dividends on preferred securities                                |                             |                              | (6,090                    | )
|                                                                                                 | Minority interest                                                |                             |                              | (7,009                    | )
|                                                                                                 |                                                                  |                             |                              |                           |  
|                                                                                                 |                                                                  |                             | Total other income (expense) |                           |  
|                                                                                                 |                                                                  |                             |                              |                           |  
|                                                                                                 | Income (loss) before income taxes                                |                             |                              | 923                       |  
|                                                                                                 | Provision (benefit) for income taxes                             |                             |                              | 639                       |  
|                                                                                                 |                                                                  |                             |                              |                           |  
|Income (Loss) Before Accounting Change                                                           |                                                                  |                             | 284                          |                           |  
|Cumulative effect on prior years of change in accounting for derivatives, net of tax             |                                                                  |                             |                             |                           |  
|Cumulative effect on prior years of change in accounting for major maintenance costs, net of tax |                                                                  |                             |                             |                           |  
|                                                                                                 |                                                                  |                             |                              |                           |  
|Net Income (Loss)                                                                                |                                                                  | $                           | 284                          |                           | $
|                                                                                                 |                                                                  |                             |                              |                           |  

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)                                 |                                                                                                                                                                                                 | $                                                                                                                                                                                                   | 284     |                           | $      
|Other comprehensive income (expense), net of tax: |                                                                                                                                                                                                 |                                                                                                                                                                                                     |         |                           |        
|                                                  | Foreign currency translation adjustments, net of income tax benefit of $316 and $2,620 for the three months and $2,665 and $3,427 for the six months ended June 30, 2001 and 2000, respectively |                                                                                                                                                                                                     |         | (4,644                    | )      
|                                                  | Unrealized gains (losses) on derivatives qualified as cash flow hedges:                                                                                                                         |                                                                                                                                                                                                     |         |                           |        
|                                                  |                                                                                                                                                                                                 | Cumulative unrealized holding losses upon adoption of a change in accounting principle, net of income tax benefit of $110.9 million                                                                 |         |                           |       
|                                                  |                                                                                                                                                                                                 | Other unrealized holding gains arising during period, net of income tax expense of $86.2 million and $68.8 million for the three months and six months ended June 30, 2001, respectively            |         |                           | 120,199
|                                                  |                                                                                                                                                                                                 | Add: reclassification adjustment for losses included in net income, net of income tax benefit of $2 million and $17.6 million for the three months and six months ended June 30, 2001, respectively |         |                           | 2,411  
|                                                  |                                                                                                                                                                                                 |                                                                                                                                                                                                     |         |                           |        
|                                                  | Net unrealized gains (losses) on derivatives qualified as cash flow hedges                                                                                                                      |                                                                                                                                                                                                     |         | 122,610                   |        
|                                                  |                                                                                                                                                                                                 |                                                                                                                                                                                                     |         |                           |        
|Other comprehensive income (expense)              |                                                                                                                                                                                                 |                                                                                                                                                                                                     | 117,966 |                           |        
|                                                  |                                                                                                                                                                                                 |                                                                                                                                                                                                     |         |                           |        
|Comprehensive Income (Loss)                       |                                                                                                                                                                                                 | $                                                                                                                                                                                                   | 118,250 |                           | $      
|                                                  |                                                                                                                                                                                                 |                                                                                                                                                                                                     |         |                           |        

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,
2001                     |            | December 31,
2000
|----------------------------- | ------------------------------------------------------------------------------ | --------------------------------- | ---------- | -----------------
|
|Assets                        |                                                                                |                                   |            |                  
|Current Assets                |                                                                                |                                   |            |                  
|                              | Cash and cash equivalents                                                      |                                   | $          | 573,443          
|                              | Accounts receivabletrade, net of allowance of $404 in 2001 and $1,126 in 2000 |                                   |            | 582,998          
|                              | Accounts receivableaffiliates                                                 |                                   |            | 153,735          
|                              | Assets under energy trading and price risk management                          |                                   |            | 166,253          
|                              | Inventory                                                                      |                                   |            | 327,203          
|                              | Prepaid expenses and other                                                     |                                   |            | 67,066           
|                              |                                                                                |                                   |            |                  
|                              |                                                                                | Total current assets              |            |                  
|                              |                                                                                |                                   |            |                  
|Investments                   |                                                                                |                                   |            |                  
|                              | Energy projects                                                                |                                   |            | 1,921,360        
|                              | Oil and gas                                                                    |                                   |            | 32,710           
|                              |                                                                                |                                   |            |                  
|                              |                                                                                | Total investments                 |            |                  
|                              |                                                                                |                                   |            |                  
|Property, Plant and Equipment |                                                                                |                                   | 11,132,905 |                  
|                              | Less accumulated depreciation and amortization                                 |                                   |            | 844,622          
|                              |                                                                                |                                   |            |                  
|                              |                                                                                | Net property, plant and equipment |            |                  
|                              |                                                                                |                                   |            |                  
|Other Assets                  |                                                                                |                                   |            |                  
|                              | Long-term receivables                                                          |                                   |            | 268,179          
|                              | Goodwill                                                                       |                                   |            | 641,631          
|                              | Deferred financing costs                                                       |                                   |            | 115,555          
|                              | Long-term assets under energy trading and price risk management                |                                   |            | 959              
|                              | Restricted cash and other                                                      |                                   |            | 117,940          
|                              |                                                                                |                                   |            |                  
|                              |                                                                                | Total other assets                |            |                  
|                              |                                                                                |                                   |            |                  
|Total Assets                  |                                                                                | $                                 | 15,257,315 |                  
|                              |                                                                                |                                   |            |                  

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

3

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|                                                |                                                                                                   | June 30,
2001                              |            | December 31,
2000 |          
|----------------------------------------------- | ------------------------------------------------------------------------------------------------- | ------------------------------------------ | ---------- | ----------------- | ---------
|
|Liabilities and Shareholder's Equity            |                                                                                                   |                                            |            |                   |          
|Current Liabilities                             |                                                                                                   |                                            |            |                   |          
|                                                | Accounts payableaffiliates                                                                       |                                            | $          | 17,325            |          
|                                                | Accounts payable and accrued liabilities                                                          |                                            |            | 513,080           |          
|                                                | Liabilities under energy trading and price risk management                                        |                                            |            | 125,463           |          
|                                                | Interest payable                                                                                  |                                            |            | 131,140           |          
|                                                | Short-term obligations                                                                            |                                            |            | 819,787           |          
|                                                | Current portion of long-term incentive compensation                                               |                                            |            | 10,557            |          
|                                                | Current maturities of long-term obligations                                                       |                                            |            | 1,413,803         |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total current liabilities                  |            |                   | 3,031,155
|                                                |                                                                                                   |                                            |            |                   |          
|Long-Term Obligations Net of Current Maturities |                                                                                                   |                                            | 6,349,278  |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Long-Term Deferred Liabilities                  |                                                                                                   |                                            |            |                   |          
|                                                | Deferred taxes and tax credits                                                                    |                                            |            | 1,580,826         |          
|                                                | Deferred revenue                                                                                  |                                            |            | 422,885           |          
|                                                | Long-term incentive compensation                                                                  |                                            |            | 40,672            |          
|                                                | Long-term liabilities under energy trading and price risk management                              |                                            |            | 185,192           |          
|                                                | Other                                                                                             |                                            |            | 305,299           |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total long-term deferred liabilities       |            |                   | 2,534,874
|                                                |                                                                                                   |                                            |            |                   |          
|Total Liabilities                               |                                                                                                   |                                            | 11,915,307 |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Minority Interest                               |                                                                                                   |                                            | 343,750    |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Preferred Securities of Subsidiaries            |                                                                                                   |                                            |            |                   |          
|                                                | Company-obligated mandatorily redeemable security of partnership holding solely parent debentures |                                            |            | 150,000           |          
|                                                | Subject to mandatory redemption                                                                   |                                            |            | 175,681           |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total preferred securities of subsidiaries |            |                   | 325,681  
|                                                |                                                                                                   |                                            |            |                   |          
|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                                                                        |                                            |            | 2,629,406         |          
|                                                | Retained earnings                                                                                 |                                            |            | 345,147           |          
|                                                | Accumulated other comprehensive loss                                                              |                                            |            | (366,106          | )        
|                                                |                                                                                                   |                                            |            |                   |          
|Total Shareholder's Equity                      |                                                                                                   |                                            | 2,672,577  |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Total Liabilities and Shareholder's Equity      |                                                                                                   | $                                          | 15,257,315 |                   | $        
|                                                |                                                                                                   |                                            |            |                   |          

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                 |                                                                                                    |                                                                      |         
|                                                     | Net income (loss)                                                                                  |                                                                      | $       
|                                                     | Adjustments to reconcile net 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 investments                               |         
|                                                     |                                                                                                    | Depreciation and amortization                                        |         
|                                                     |                                                                                                    | Deferred taxes and tax credits                                       |         
|                                                     |                                                                                                    | Amortization of discount on short-term obligations                   |         
|                                                     |                                                                                                    | Gain on sale of assets                                               |         
|                                                     |                                                                                                    | Cumulative effect on prior years of change in accounting, net of tax |         
|                                                     | (Increase) decrease in accounts receivable                                                         |                                                                      |         
|                                                     | Increase in inventory                                                                              |                                                                      |         
|                                                     | Decrease in prepaid expenses and other                                                             |                                                                      |         
|                                                     | Increase (decrease) in accounts payable and accrued liabilities                                    |                                                                      |         
|                                                     | Increase in interest payable                                                                       |                                                                      |         
|                                                     | Decrease in long-term incentive compensation                                                       |                                                                      |         
|                                                     | Decrease in net assets under risk management                                                       |                                                                      |         
|                                                     | Other, net                                                                                         |                                                                      |         
|                                                     |                                                                                                    |                                                                      |         
|                                                     |                                                                                                    | Net cash provided by (used in) operating activities                  |         
|                                                     |                                                                                                    |                                                                      |         
|Cash Flows From Financing Activities                 |                                                                                                    |                                                                      |         
|                                                     | Borrowings long-term obligations                                                                   |                                                                      |         
|                                                     | Payments on long-term obligations                                                                  |                                                                      |         
|                                                     | Short-term financing, net                                                                          |                                                                      |         
|                                                     | Cash dividends to parent                                                                           |                                                                      |         
|                                                     | Issuance of preferred securities                                                                   |                                                                      |         
|                                                     |                                                                                                    |                                                                      |         
|                                                     |                                                                                                    | Net cash provided by financing activities                            |         
|                                                     |                                                                                                    |                                                                      |         
|Cash Flows From Investing Activities                 |                                                                                                    |                                                                      |         
|                                                     | Investments in and loans to energy projects                                                        |                                                                      |         
|                                                     | Purchase of common stock of acquired companies                                                     |                                                                      |         
|                                                     | Capital expenditures                                                                               |                                                                      |         
|                                                     | Proceeds from sale of interest in projects                                                         |                                                                      |         
|                                                     | Decrease in restricted cash                                                                        |                                                                      |         
|                                                     | Other, net                                                                                         |                                                                      |         
|                                                     |                                                                                                    |                                                                      |         
|                                                     |                                                                                                    | Net cash used in investing activities                                |         
|                                                     |                                                                                                    |                                                                      |         
|Effect of exchange rate changes on cash              |                                                                                                    |                                                                      | (51,217 
|                                                     |                                                                                                    |                                                                      |         
|Net increase (decrease) in cash and cash equivalents |                                                                                                    |                                                                      | (389,422
|Cash and cash equivalents at beginning of period     |                                                                                                    |                                                                      | 962,865 
|                                                     |                                                                                                    |                                                                      |         
|Cash and cash equivalents at end of period           |                                                                                                    | $                                                                    | 573,443 
|                                                     |                                                                                                    |                                                                      |         

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, 2001

NOTE 1.  GENERAL

We have made all adjustments, including recurring accruals, 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, 2001 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, 2000 and 1999, included in our 2000 Annual Report
on Form 10-K filed with the Securities and Exchange Commission on April 2, 2001. We follow the same accounting policies for interim reporting purposes, with the exception of
the change in accounting for derivatives (see Note 2). 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.

Mission Energy Holding Company

On June 8, 2001, Edison International created Mission Energy Holding Company as a wholly-owned indirect subsidiary. Mission Energy Holding's principal
asset is our common stock. As previously disclosed by Edison International, in July 2001, Mission Energy Holding issued $800 million of 13.50% senior secured notes due 2008. Concurrently
with the consummation of the offering of its senior secured notes, Mission Energy Holding borrowed $385 million under a new term loan. The senior secured notes and the term loan are secured by
a first priority security interest in our common stock. The respective rights, remedies and priorities of the holders of the senior secured notes and the lenders with respect to our stock are governed
by intercreditor arrangements. Both the senior secured notes and the term loan also have security interests in interest reserve accounts, covering the interest payable on those obligations for the
first two years. We have not guaranteed either the senior secured notes or the term loan, both of which are non-recourse to us. The net proceeds of the offering and the term loan not
deposited into the respective interest escrow accounts were used to pay a dividend to Mission Energy Holding's parent, The Mission Group, which in turn loaned the net proceeds to its parent, Edison
International. Edison International used the funds to repay a portion of its indebtedness that matures in 2001. The Mission Energy Holding financing documents contain restrictions on our ability and
the ability of our subsidiaries to enter into specified transactions or engage in specified business activities and require in some instances that we obtain the approval of the Mission Energy Holding
board of directors. Our articles of incorporation bind us to the restrictions in the Mission Energy Holding financing documents by restricting our ability to enter into specified transactions or
engage in specified business activities, as set forth in the Mission Energy Holding financing documents, without shareholder approval.

California Power Crisis

Edison International, our ultimate parent company, is a holding company. Edison International is also the corporate parent of Southern California Edison
Company, an electric utility that buys and sells power in California. In the past year, various market conditions and other factors have resulted in
higher wholesale power prices to California utilities. At the same time, two of the three major California utilities, Southern California Edison and Pacific Gas and Electric Co., have operated under a
retail rate freeze. As a result, there has been a significant under recovery of costs by Southern

6

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California Edison and Pacific Gas and Electric, and each of these companies has failed to make payments due to power suppliers, including us, and others. Given these and other payment defaults,
Southern California Edison could face bankruptcy at any time. Pacific Gas and Electric filed a voluntary bankruptcy petition on April 6, 2001. Other results of the under recoveries could
include an end to the retail rate freeze and significant retail rate increases. A number of federal and state, legislative and regulatory initiatives addressing the issues of the California electric
power industry have been proposed, including wholesale rate caps, retail rate increases, acceleration of power plant permitting and state entry into the power market. Many of these activities are
ongoing. These activities may result in a restructuring of the California power market. At this time, these activities are in their preliminary stages, and it is not possible to estimate their likely
ultimate outcome. For more information on how the current California power crisis affects us and our investments, see "Note 6. Commitments and ContingenciesThe
California Power Crisis."

NOTE 2.  CHANGES IN ACCOUNTING

Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The Statement 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. The Statement 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. The ineffective portion of a derivative's change in fair value is immediately
recognized in earnings.

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 record all derivatives at fair value unless the derivatives
qualify 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, as amended, are met. The majority of our physical long-term
power and fuel contracts, and the similar business activities of our affiliates, qualify under this exception.

The
majority of our remaining risk management activities, including forward sales contracts from our Homer City plant, qualify for treatment under SFAS No. 133 as cash flow
hedges with appropriate adjustments made to other comprehensive income. The hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project
in Australia qualifies as a cash flow hedge. This contract could not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical
delivery. Some of our derivatives did not qualify for either the normal sales and purchases exception or as cash flow hedges. These derivatives are recorded at fair value with subsequent changes in
fair value recorded through the income statement. The majority of our activities related to the Ferrybridge and Fiddler's Ferry power

7

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plants in the United Kingdom and fuel contracts related to the Collins Station in Illinois do not qualify for either the normal purchases and sales exception or as cash flow hedges. In both these
situations, we could not conclude, based on information available at June 30, 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 are recorded at fair value, with subsequent changes in fair value reflected in net gains (losses) from energy
trading and price risk management in the consolidated income statement.

As
a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under our prior accounting policy. We recorded a
$6 million, after tax, increase
to net income as the cumulative change in the accounting for derivatives during the quarter ended March 31, 2001. In addition, we recorded a $230 million, after tax, unrealized holding
loss upon adoption of a change in accounting principle reflected in accumulated other comprehensive loss in the consolidated balance sheet. During the quarter ended June 30, 2001, we recorded a
$120 million, after tax, unrealized holding gain reflected in accumulated other comprehensive loss in the consolidated balance sheet. We recorded a loss of $0.3 million, after tax, and
$7.4 million, after tax, for the quarter ended and six months ended June 30, 2001, respectively, as the change in the fair value of derivatives required under SFAS No. 133 that
previously qualified for hedge accounting. We also recorded a net gain of $1.5 million and $1.6 million for the quarter ended and six months ended June 30, 2001, respectively,
representing the amount of cash flow hedges' ineffectiveness, reflected in net gains (losses) from energy trading and price risk management in the consolidated income statement.

The
Derivative Implementation Group of the Financial Accounting Standards Board has recently provided guidance on the normal sales and purchases exception that affects classification
on commodity contracts. We did not use the normal sales and purchases exception for forward sales contracts from our Homer City plant due to our net settlement procedures with counterparties for the
period between January 1, 2001 through June 30, 2001. Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board extended the normal
sales and purchases exception to include forward sales contracts subject to net settlement procedures with counterparties. Accordingly, we intend to use the normal sales and purchases exception for
our Homer City forward sales contracts commencing July 1, 2001 and plan to record a cumulative change in the accounting for derivatives during the quarter ended September 30, 2001. We
are currently evaluating the impact of the implementation guidance on our remaining commodity contracts, which would be accounted for on a prospective basis.

Through
December 31, 1999, we accrued for major maintenance costs incurred during the period between turnarounds (referred to as "accrue in advance" accounting method). In
March 2000, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is considered preferable based
on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we recorded a $17.7 million, after
tax, increase to net income, as a cumulative change in the accounting for major maintenance costs during the quarter ended March 31, 2000.

8

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NOTE 3.  INVENTORY

Inventory is stated at the lower of weighted average cost or market. Inventory at June 30, 2001 and December 31, 2000 consisted of the following:

June 30,
2001

December 31,
2000(Unaudited)(in millions)Coal and fuel oil

$
252.5

$
207.8Spare parts, materials and supplies


74.7


72.1Total

$
327.2

$
279.9


NOTE 4.  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, 2000

$
(146.8
)
$


$
(146.8
)Current period change


(101.2
)

(118.1
)

(219.3
)Balance at June 30, 2001 (Unaudited)

$
(248.0
)
$
(118.1
)
$
(366.1
)


Unrealized
gains (losses) on cash flow hedges at June 30, 2001 included forward sales contracts from our Homer City plant that did not meet the normal sales and purchases
exception under SFAS No. 133 due to our net settlement procedures with counterparties. In addition, the hedge agreement we have with the State Electricity Commission of Victoria for
electricity prices from our Loy Yang B project in Australia qualifies as a cash flow hedge. This contract also could not qualify under the normal sales and purchases exception because financial
settlement of the contract occurs without physical delivery. Approximately 93% of our accumulated other comprehensive loss at June 30, 2001 related to net unrealized losses on cash flow hedges
resulting from these contracts. These net losses arise from current forecasts of future electricity prices in these markets greater than our contract prices. Although
the contract prices are below the current market prices, we believe that prices included in our contracts mitigate price risk associated with future changes in market prices and are at prices that
meet our profit objectives. Assuming the long-term contract with the State Electricity Commission of Victoria continues to qualify as a cash flow hedge, future changes in the forecast of
market prices for contract volumes included in this agreement will increase or decrease our other comprehensive income without significantly affecting our net income.

As
our hedged positions are realized, approximately $11.9 million, after tax, of the net unrealized losses on cash flow hedges will be reclassified into earnings during the
remainder of 2001. Management expects that these net unrealized losses will be offset when the hedged items are recognized in earnings. The maximum period over which a cash flow hedge is designated,
excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is 15 years.

9

---

NOTE 5.  ACQUISITIONS AND DISPOSITIONS

Acquisitions

In February 2001, we completed the acquisition of a 50% interest in CBK Power Co. Ltd. in exchange for $20 million. CBK Power has entered
into a 25-year build-rehabilitate-transfer-and-operate agreement with National Power Corporation related to the 728 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric
project located in the Philippines. Financing for this $460 million project comprises equity commitments of $117 million (our 50% share is $58.5 million) required to be made upon
completion of the rehabilitation and expansion, currently scheduled in 2003, and debt financing which is in place for the remainder of the cost for this project.

During
the second quarter of 2001, we completed the purchase of additional shares of Contact Energy for NZ$152 million, thereby increasing our ownership interest from 42.6% to
51.2%. Accordingly, we began accounting for Contact Energy on a consolidated basis effective June 1, 2001, upon acquisition of a controlling interest. Prior to June 1, 2001, we used the
equity method of accounting for Contact Energy. In order to finance this purchase, we obtained a NZ$135 million, 364-day bridge loan from an investment bank under a credit facility
which is to be syndicated by the bank. In addition to other security arrangements, a security interest over all Contact Energy shares held has been provided as collateral. In June and
July 2001, we issued through one of our subsidiaries new preferred securities to repay the bridge loan. On July 2, 2001, we redeemed NZ$400 million EME Taupo preferred
securities from the existing holders. Funding for the redemption of the existing preferred securities was provided by a NZ$400 million credit facility scheduled to mature in July 2005.
The financing documents governing the credit facility provide that the credit facility may be funded under either, or a combination of, a letter of credit facility or a revolving credit facility. The
NZ$400 million was originally funded as a revolving credit facility.

Dispositions

On June 25, 2001, Texaco Power & Gasification Holdings Inc. repurchased a 50% interest in the Sunrise project for $84 million,
which amount totaled 50% of the project costs, prior to commercial operations. Commercial operations commenced on June 27, 2001. On June 25, 2001, we entered into a long-term
power purchase agreement with the California Department of Water Resources. The total estimated construction cost of this project through 2003 is approximately $455 million. The project intends
to obtain project financing for a portion of the capital costs.

On
June 29, 2001, we completed the sale of our 25% interest in the Hopewell project to the existing partner. Proceeds from the sale were $26.5 million. We recorded a
gain on the sale of $5.4 million ($2.8 million after tax).

Subsequent
to June 30, 2001, we have entered into agreements, subject to obtaining consents from third parties and other conditions precedent to closing, for the sale of our
interests in the EcoEléctrica,
Gordonsville, Commonwealth Atlantic, James River and Saguaro projects. In addition, we are currently offering for sale our interests in the Brooklyn Navy Yard and Nevada Sun-Peak projects.
We expect the proceeds from the sale of our interests in the above projects, if completed, will be in excess of our book value ($482 million at June 30, 2001). We are also offering for
sale the Ferrybridge and Fiddler's Ferry plants in the United Kingdom. See "Management's Discussion and Analysis of Financial

10

---

Condition and Results of OperationsLiquidity and Capital ResourcesSubsidiary Financing PlansStatus of Edison First Power Loan."

NOTE 6.  COMMITMENTS AND CONTINGENCIES

Capital Commitments

The following table summarizes our consolidated capital commitments as of June 30, 2001. Details regarding these capital commitments are discussed in
the sections referenced.

|Type of Commitment                                     |  | Estimated
Cost in U.S. $ |  | Time
Period |  | Discussed Under                                                                                                                                          
|------------------------------------------------------ |  | ------------------------ |  | ----------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------
|
|New Gas-Fired Generation                               |  | $250                     |  | by 2003     |  | Illinois PlantsPower Purchase Agreements, included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2000 
|New Gas-Fired Generation                               |  | 986*                     |  | 2001-2004   |  | Edison Mission Energy Master Turbine Lease, included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2000
|Environmental Improvements at our Project Subsidiaries |  | 494                      |  | 2001-2005   |  | Management's Discussion and Analysis of Financial Condition and Results of OperationsEnvironmental Matters and Regulations                              
|Project Acquisition for the Italian Wind Projects      |  | 8                        |  | 2001-2002   |  | Firm Commitment for Asset Purchase                                                                                                                       
|Equity Contribution for the Sunrise Project            |  | 123                      |  | 2001-2003   |  | Firm Commitments to Contribute Project Equity                                                                                                            
|Equity Contribution for the Italian Wind Projects      |  | 1                        |  | 2001-2002   |  | Firm Commitments to Contribute Project Equity                                                                                                            
|Equity Contribution for the CBK Project                |  | 59                       |  | 2003        |  | Firm Commitments to Contribute Project Equity                                                                                                            

---

11

---

Firm Commitment for Asset Purchase

Project

Local Currency

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

18 billion Italian Lira

$
7.9


---

Firm Commitments to Contribute Project Equity

Project

Local Currency

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

3 billion Italian Lira

$
1.4CBK Project(ii)




58.5Sunrise Project(iii)




122.9


---

Firm
commitments to contribute project equity could be accelerated due to events of default as defined in the non-recourse project financing facilities. Management does
not believe that these events of default will occur to require acceleration of the firm commitments.

Other Commitments

Homer City

Edison Mission Energy has guaranteed to the bondholders, banks and other secured parties that financed the acquisition of the Homer City plant the performance
and payment when due by Edison Mission Holdings Co. of its obligations in respect of specified senior debt, up to $42 million. This

12

---

guarantee will be available until December 31, 2001, after which time Edison Mission Energy will have no further obligations under this guarantee. To satisfy the requirements under the Edison
Mission Holdings Co. bank financing to have a debt service reserve account balance in an amount equal to six months' debt service, Edison Mission Energy provides a guarantee of Edison Mission
Holdings' obligations in the amount of $9 million to the lenders involved in the bank financing.

Credit Support for Trading and Price Risk Management Activities

Our 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 us. The majority of Edison Mission Marketing & Trading's contracts have various standards of creditworthiness, including the maintenance of specified credit ratings. If Edison
Mission Marketing & Trading does not maintain its investment grade rating or if other events adversely affect its financial position, a third party could request Edison Mission
Marketing & Trading to provide adequate assurance. Adequate assurance could take the form of supplying additional financial information, additional guarantees, collateral, letters of credit or
cash. Failure to provide adequate assurance could result in a counterparty liquidating an open position and filing a claim against Edison Mission Marketing & Trading for any losses.

The
California power crisis has adversely affected the liquidity of West Coast trading markets and, to a lesser extent, other regions in the United States. Our trading and price risk
management activity has been reduced as a result of these market conditions and uncertainty regarding the effect of the power crisis on our affiliate, Southern California Edison. It is not certain
that resolution of the California power crisis will occur in 2001 or that, if resolved, we will be able to conduct trading and price risk management activities in a manner that will be favorable to
us.

Subsidiary Indemnification Agreements

Some of our subsidiaries have entered into indemnification agreements, under which the subsidiaries have 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, 2001, if payment were required, would be $246 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.

Other

In support of the businesses of our subsidiaries, we have made, from time to time, guarantees, and have entered into indemnity agreements with respect to our
subsidiaries' obligations like those for debt service, fuel supply or the delivery of power, and have entered into reimbursement agreements with respect to letters of credit issued to third parties to
support our subsidiaries' obligations. We may incur

13

---

additional guaranty, indemnification, and reimbursement obligations, as well as obligations to make equity and other contributions to projects in the future.

Contingencies

The California Power Crisis

In the past year, various market conditions and other factors have resulted in higher wholesale power prices to California utilities. At the same time, two of
the three major California utilities, Southern California Edison and Pacific Gas and Electric, have operated under a retail rate freeze. As a result, there has been a significant under recovery of
costs by Southern California Edison and Pacific Gas and Electric, and each of these companies has failed to make payments due to power suppliers, including us, and others. Given these and other
payment defaults, Southern California Edison could face bankruptcy at any time. Pacific Gas and Electric filed a voluntary bankruptcy petition on April 6, 2001. Edison International, our
ultimate parent company, is also the corporate parent of Southern California
Edison. For a description of this contingency and the California power crisis, see "Management's Discussion and Analysis of Financial Condition and Results of
OperationsThe California Power Crisis and Our Response."

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. Our investment in the Paiton project was $503 million at June 30, 2001. Paiton Energy is in continuing negotiations on a
long-term restructuring of the tariff under a long-term power purchase agreement with the state-owned electric utility company, PT PLN. Paiton Energy and PT PLN agreed on a
Phase I Agreement for the period from January 1, 2001 through June 30, 2001. This agreement provided for fixed monthly payments aggregating $108 million over its
six-month duration and for the payment for energy delivered to PT PLN from the plant during this period. PT PLN made all fixed payments due under the Phase I Agreement totaling
$108 million as scheduled. Paiton Energy received lender approval of the Phase I Agreement, and Paiton Energy has also entered into a lender interim agreement under which lenders have
effectively agreed to interest-only payments and to deferral of principal payments while Paiton Energy and PT PLN seek a long-term restructuring of the tariff. The lenders have
agreed to extend that agreement through December 31, 2001. Paiton Energy and PT PLN intended to complete the negotiations of the future phases of a new long-term tariff during the
six-month duration of the Phase I Agreement. Although Paiton Energy and PT PLN did not complete negotiations on a long-term restructuring of the tariff by June 30, 2001,
Paiton Energy and PT PLN have signed an agreement providing for an extension of the Phase I Agreement from July 1, 2001 to September 30, 2001. Paiton Energy is continuing to generate
electricity to meet the power demand in the region and believes that PT PLN will continue to agree to make payments for electricity on an interim basis beyond June 30, 2001 while negotiations
regarding the long-term restructuring of the tariff continue. Although completion of negotiations may be delayed, Paiton Energy continues to believe that negotiations on the
long-term restructuring of the tariff will be successful. For a more detailed discussion of the restructuring of the tariff and related matters, refer to "Commitments and

14

---

ContingenciesPaiton" in Item 7. of Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2000.

Any
material modifications of the power purchase agreement resulting from the continuing negotiation of a new long-term tariff could require a renegotiation of the Paiton
project's debt agreements. The impact of any such renegotiations with PT PLN, the Government of Indonesia or the project's creditors on our expected return on our investment in Paiton Energy is
uncertain at this time; however, we believe that we will ultimately recover our investment in the project.

Brooklyn Navy Yard

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

Contingent Obligations to Contribute Project Equity

Project

Local Currency

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



$
5.3ISAB(ii)

84 billion Italian Lira


36.5


---

For
more information on the Paiton project, see "Paiton" above.

15

---

We
are not aware of any other significant contingent obligations or obligations to contribute project equity other than as noted above and equity contributions to be made by us to
meet capital calls by partnerships who own qualifying facilities that have power purchase agreements with Southern California Edison and Pacific Gas and Electric. See "Management's Discussion and
Analysis of Financial Condition and Results of OperationsThe California Power Crisis and Our Response" for further discussion.

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, Central Asia, Middle East and Africa. 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,
Central Asia,
Middle East
and Africa |  | Corporate/
Other |         | Total
|----------------------- |  | -------- | ------- | ------------ | - | -------------------------------------------- |  | ---------------- | ------- | -----
|
|June 30, 2001           |  |          |         |              |   |                                              |  |                  |         |      
|Operating revenues      |  | $        | 503.3   |              | $ | 96.9                                         |  | $                | 215.1   |      
|Operating income (loss) |  |          | 152.3   |              |   | 45.4                                         |  |                  | (4.5    | )    
|Total assets            |  | $        | 6,724.0 |              | $ | 3,115.2                                      |  | $                | 4,749.7 |      
|June 30, 2000           |  |          |         |              |   |                                              |  |                  |         |      
|Operating revenues      |  | $        | 419.7   |              | $ | 42.5                                         |  | $                | 261.0   |      
|Operating income (loss) |  |          | 82.8    |              |   | 19.4                                         |  |                  | 67.7    |      
|Total assets            |  | $        | 7,759.4 |              | $ | 2,798.7                                      |  | $                | 4,865.7 |      

|Six Months Ended        |  | Americas |         | Asia Pacific |   | Europe,
Central Asia,
Middle East
and Africa |  | Corporate/
Other |         | Total
|----------------------- |  | -------- | ------- | ------------ | - | -------------------------------------------- |  | ---------------- | ------- | -----
|
|June 30, 2001           |  |          |         |              |   |                                              |  |                  |         |      
|Operating revenues      |  | $        | 912.0   |              | $ | 145.7                                        |  | $                | 526.8   |      
|Operating income (loss) |  |          | 228.6   |              |   | 71.0                                         |  |                  | 72.9    |      
|Total assets            |  | $        | 6,724.0 |              | $ | 3,115.2                                      |  | $                | 4,749.7 |      
|June 30, 2000           |  |          |         |              |   |                                              |  |                  |         |      
|Operating revenues      |  | $        | 697.6   |              | $ | 97.5                                         |  | $                | 665.0   |      
|Operating income (loss) |  |          | 81.1    |              |   | 47.0                                         |  |                  | 208.1   |      
|Total assets            |  | $        | 7,759.4 |              | $ | 2,798.7                                      |  | $                | 4,865.7 |      

16

---

NOTE 8.  INVESTMENTS

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

Three Months Ended
June 30,

Six Months Ended
June 30,2001

2000

2001

2000(Unaudited) (in millions)Operating Revenues

$
418.0

$
177.3

$
794.2

$
293.8Operating Income


151.2


52.7


231.1


88.7Net Income


151.3


60.0


231.2


95.6


The
following table presents summarized financial information of the significant subsidiary investment in oil and gas accounted for by the equity method. The significant subsidiary is
Four Star Oil & Gas Company, of which we own 36 percent.

Three Months Ended
June 30,

Six Months Ended
June 30,2001

2000

2001

2000(Unaudited) (in millions)Operating Revenues

$
85.8

$
91.8

$
198.0

$
169.7Operating Income


55.7


50.9


142.4


91.2Net Income


31.9


31.7


88.7


55.9


17

---

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

The following discussion contains forward-looking statements. These statements are based on our current plans and expectations and
involve risks and uncertainties that 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.

General

We are an independent power producer engaged in the business of developing, acquiring, owning or leasing and operating electric power generation facilities
worldwide. We also conduct energy trading and price risk management activities in power markets open to competition. Edison International is our ultimate parent company. Edison International also owns
Southern California Edison Company, one of the largest electric utilities in the United States. We were formed in 1986 with two domestic operating projects. As of June 30, 2001, we owned
interests in 33 domestic and 39 international operating power projects with an aggregate generating capacity of 27,798 megawatts (MW), of which our share was 22,923 MW. At that date, one domestic and
five international projects, totaling 1,551 MW of generating capacity, of which our anticipated share will be approximately 926 MW, were in construction. At June 30, 2001, we had consolidated
assets of $15.3 billion and total shareholder's equity of $2.7 billion.

Our
operating revenues are derived primarily from electric revenues and equity in income from power projects. Electric revenues accounted for 83% and 95% of our total operating
revenues during the three-month periods ended June 30, 2001 and 2000, respectively, and 85% and 94% of our total operating revenues during the six-month periods ended
June 30, 2001 and 2000, respectively. Our consolidated operating revenues during those years also include equity in income from oil and gas investments, net gains (losses) from energy trading
and price risk management activities and revenues attributable to operation and maintenance services.

Acquisitions and Dispositions

Acquisitions

In February 2001, we completed the acquisition of a 50% interest in CBK Power Co. Ltd. in exchange for $20 million. CBK Power has entered
into a 25-year build-rehabilitate-transfer-and-operate agreement with National Power Corporation related to the 728 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric
project located in the Philippines. Financing for this $460 million project comprises equity commitments of $117 million (our 50% share is $58.5 million) required to be made upon
completion of the rehabilitation and expansion, currently scheduled in 2003, and debt financing which is in place for the remainder of the cost for this project.

18

---

During the second quarter of 2001, we completed the purchase of additional shares of Contact Energy for NZ$152 million, thereby increasing our ownership interest from 42.6% to
51.2%. Accordingly, we began accounting for Contact Energy on a consolidated basis effective June 1, 2001, upon acquisition of a controlling interest. Prior to June 1, 2001, we used the
equity method of accounting for Contact Energy. In order to finance this purchase, we obtained a NZ$135 million, 364-day bridge loan from an investment bank under a credit facility
which is to be syndicated by the bank. In addition to other security arrangements, a security interest over all Contact Energy shares held has been provided as collateral. In June and
July 2001, we issued through one of our subsidiaries new preferred securities to repay the bridge loan. On July 2, 2001, we redeemed NZ$400 million EME Taupo preferred
securities from the existing holders. Funding for the redemption of the existing preferred securities was provided by a NZ$400 million credit facility scheduled to mature in July 2005.
The financing documents governing the credit facility provide that the credit facility may be funded under either, or a combination of, a letter of credit facility or a revolving credit facility. The
NZ$400 million was originally funded as a revolving credit facility.

Dispositions

On June 25, 2001, Texaco Power & Gasification Holdings Inc. repurchased a 50% interest in the Sunrise project for $84 million,
which amount totaled 50% of the project costs, prior to commercial operations. Commercial operations commenced on June 27, 2001. On June 25, 2001, we entered into a long-term
power purchase agreement with the California Department of Water Resources. The total estimated construction cost of this project through 2003 is approximately $455 million. The project intends
to obtain project financing for a portion of the capital costs.

On
June 29, 2001, we completed the sale of our 25% interest in the Hopewell project to the existing partner. Proceeds from the sale were $26.5 million. We recorded a
gain on the sale of $5.4 million ($2.8 million after tax).

Subsequent
to June 30, 2001, we have entered into agreements, subject to obtaining consents from third parties and other conditions precedent to closing, for the sale of our
interests in the EcoEléctrica, Gordonsville, Commonwealth Atlantic, James River and Saguaro projects. In addition, we are currently offering for sale our interests in the Brooklyn Navy
Yard and Nevada Sun-Peak projects. We expect the proceeds from the sale of our interests in the above projects, if completed, will be in excess of our book value ($482 million at
June 30, 2001). We are also offering for sale the Ferrybridge and Fiddler's Ferry plants in the United Kingdom. See "Liquidity and Capital ResourcesSubsidiary
Financing PlansStatus of Edison First Power Loan."

Mission Energy Holding Company

On June 8, 2001, Edison International created Mission Energy Holding Company as a wholly-owned indirect subsidiary. Mission Energy Holding's principal
asset is our common stock. As previously disclosed by Edison International, in July 2001, Mission Energy Holding issued $800 million of 13.50% senior secured notes due 2008. Concurrently
with the consummation of the offering of its senior secured notes, Mission Energy Holding borrowed $385 million under a new term loan. The senior secured notes and the term loan are secured by
a first priority security interest in our common stock. The respective rights, remedies and priorities of the holders of the senior secured notes and the lenders with respect to our stock are governed
by intercreditor arrangements. Both the senior secured notes and the term loan also have security interests in interest reserve accounts, covering the interest payable on those obligations for the
first two years. We have not guaranteed either the senior secured notes or the term loan, both of which are non-recourse to us. The net proceeds of the offering and the term loan not
deposited into the respective interest escrow accounts were used to pay a dividend to Mission Energy Holding's parent, The Mission Group, which in turn loaned the net proceeds to its parent, Edison
International. Edison International used the funds to repay a portion of its indebtedness that

19

---

matures in 2001. The Mission Energy Holding financing documents contain restrictions on our ability and the ability of our subsidiaries to enter into specified transactions or engage in specified
business activities and require in some instances that we obtain the approval of the Mission Energy Holding board of directors. Our articles of incorporation bind us to the restrictions in the Mission
Energy Holding financing documents by restricting our ability to enter into specified transactions or engage in specified business activities, as set forth in the Mission Energy Holding financing
documents, without shareholder approval.

Results of Operations

We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific,
and Europe, Central Asia, Middle East and Africa.

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 those entities.

Americas

|                                                                 |                          | Three Months Ended
June 30, |       | Six Months Ended
June 30, |  
|---------------------------------------------------------------- | ------------------------ | --------------------------- | ----- | ------------------------- | -
|
|
|Operating revenues                                               |                          | $                           | 379.7 |                           | $
|Net gains (losses) from energy trading and price risk management |                          |                             | 13.6  |                           |  
|Equity in income from investments                                |                          |                             | 110.0 |                           |  
|                                                                 |                          |                             |       |                           |  
|                                                                 | Total operating revenues |                             |       | 503.3                     |  
|Fuel and plant operations                                        |                          |                             | 305.8 |                           |  
|Depreciation and amortization                                    |                          |                             | 40.1  |                           |  
|Administrative and general                                       |                          |                             | 5.1   |                           |  
|                                                                 |                          |                             |       |                           |  
|                                                                 | Operating income         |                             | $     | 152.3                     |  
|                                                                 |                          |                             |       |                           |  

Operating Revenues

Operating revenues decreased $11.1 million for the second quarter ended June 30, 2001, compared to the corresponding period of 2000. The decrease
was primarily due to lower dispatch from the coal units at the Illinois Plants as a result of lower market prices during the second quarter of 2001. Operating revenues increased $50.1 million
for the six months ended June 30, 2001, compared to the same prior year period. The increase resulted from higher electric revenues from the Homer City plant due to higher energy prices and
from the Illinois Plants due to increased generation from the coal units as a result of higher market prices, as compared to the same prior year period.

Net
gains from energy trading activities were $6.5 million and $2.4 million for the second quarter and six months ended June 30, 2001, respectively. There were no
comparable gains or losses for the same prior year periods. Total gains and losses from price risk management activities increased $39.2 million and $63.9 million for the second quarter
and six months ended June 30, 2001, respectively, compared to the corresponding periods of 2000. The increase in gains was primarily due to

20

---

realized and unrealized gains for a gas swap purchased to hedge a portion of our gas price risk related to our share of gas production in Four Star, an oil and gas company in which we have a minority
interest and which we account for under the equity method. Although we believe the gas swap hedges our gas price risk, hedge accounting is not permitted for our investments accounted for on the equity
method. Partially offsetting this gain in the second quarter and six months ended June 30, 2001 was a loss resulting from the change in market value of future contracts with respect to fuel
purchases at the Illinois Plants that did not qualify for hedge accounting under SFAS No. 133.

Equity
in income from investments increased $49 million and $98 million during the second quarter and six months ended June 30, 2001, respectively, compared to
the same prior year periods. The increase was primarily the result of higher revenues from cogeneration projects due to higher energy pricing during the six-month period ended
June 30, 2001, and higher revenues from oil and gas investments due to higher oil and gas prices in the first quarter of 2001.

Due
to warmer weather during the summer months, electric revenues generated from the Homer City plant 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 for our West Coast power
investments.

Operating Expenses

Fuel and plant operations increased $19.2 million and $76.9 million for the second quarter and six months ended June 30, 2001,
respectively, compared to the corresponding periods of the prior year. The increase in plant operations resulted from lease costs related to the sale-leaseback commitments for the
Powerton-Joliet power facilities and the Collins gas and oil-fired power plant. There were no comparable lease costs for the Powerton-Joliet power facilities during the six months ended
June 30, 2000. In addition, plant operations increased due to higher major maintenance costs at the Illinois Plants during the six-month period ended June 30, 2001. The
increase in fuel expense for the six months ended June 30, 2001, as compared to the same period last year, resulted from higher fuel costs at the Illinois Plants primarily due to higher natural
gas and fuel oil prices.

Depreciation
and amortization expense decreased $10.2 million and $20.9 million for the second quarter and six months ended June 30, 2001, respectively, compared
to the same periods last year. The decrease resulted from lower depreciation expense at the Illinois Plants related to the sale-leaseback transaction for the Powerton-Joliet power
facilities to third-party lessors in August 2000.

Administrative
and general expenses for the quarter ended and six months ended June 30, 2001 consist of administrative and general expenses incurred at our trading operations
in Boston, Massachusetts. Prior to September 1, 2000, the acquisition date of Citizens Power, administrative and general expenses incurred by our own marketing operations were reflected in
Corporate/Other administrative and general expenses.

Operating Income

Operating income increased $69.5 million and $147.5 million during the second quarter and six months ended June 30, 2001, respectively,
compared to the corresponding periods of the prior year. The increase was primarily due to operating income from the Homer City plant, equity in income from investments in energy projects and gains
from price risk management activities discussed above.

21

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Asia Pacific

|                                                        |                          | Three Months Ended
June 30, |      | Six Months Ended
June 30,
|------------------------------------------------------- | ------------------------ | --------------------------- | ---- | -------------------------
|
|
|Operating revenues                                      |                          | $                           | 92.4 |                          
|Net gains from energy trading and price risk management |                          |                             | 0.6  |                          
|Equity in income from investments                       |                          |                             | 3.9  |                          
|                                                        |                          |                             |      |                          
|                                                        | Total operating revenues |                             |      | 96.9                     
|Fuel and plant operations                               |                          |                             | 43.2 |                          
|Depreciation and amortization                           |                          |                             | 8.3  |                          
|                                                        |                          |                             |      |                          
|                                                        | Operating income         |                             | $    | 45.4                     
|                                                        |                          |                             |      |                          

Operating Revenues

Operating revenues increased $51.6 million and $45.5 million for the second quarter and six months ended June 30, 2001, respectively,
compared to the corresponding periods of 2000. The increase was primarily due to consolidating Contact Energy operating revenues due to acquiring a controlling interest in the project, effective
June 1, 2001. The increase was partially offset by lower electric revenues from the Loy Yang B plant in Australia due to a 14.4% decrease in the average exchange rate of the Australian dollar
compared to the U.S. dollar at the six-month period ended June 30, 2001, compared to the same prior year period.

Net
gains from price risk management activities were $0.6 million and $0.1 million for the second quarter and six months ended June 30, 2001, respectively. There
were no comparable gains or losses for the same prior year periods. The gains primarily represent the ineffective portion of a long-term contract with the State Electricity Commission of
Victoria and interest rate swaps entered into by the Loy Yang B plant, which are derivatives that qualified as cash flow hedges under SFAS No. 133. See "Note 4. Accumulated
Other Comprehensive Income (Loss)," for further discussion.

Equity
in income from investments increased $2.2 million and $2.6 million during the second quarter and six months ended June 30, 2001, respectively, compared to
the same prior year periods. The increase primarily reflects gains from Contact Energy through May 31, 2001 due to higher wholesale electricity prices in the current year.

Operating Expenses

Fuel and plant operations increased $27.5 million and $25.7 million for the second quarter and six months ended June 30, 2001,
respectively, compared to the corresponding periods of 2000. The increase was primarily due to consolidating Contact Energy operating expenses, effective June 1, 2001.

Operating Income

Operating income increased $26 million and $24 million during the second quarter and six months ended June 30, 2001, respectively,
compared to the corresponding periods of 2000. The increase was primarily due to consolidating Contact Energy results of operations, effective June 1, 2001. Prior to June 1, 2001, we
used the equity method of accounting for Contact Energy.

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Europe, Central Asia, Middle East and Africa

|                                                         |                          | Three Months Ended
June 30, |       | Six Months Ended
June 30, |  
|-------------------------------------------------------- | ------------------------ | --------------------------- | ----- | ------------------------- | -
|
|
|Operating revenues                                       |                          | $                           | 217.9 |                           | $
|Net losses from energy trading and price risk management |                          |                             | (3.9  | )                         |  
|Equity in income (loss) from investments                 |                          |                             | 1.1   |                           |  
|                                                         |                          |                             |       |                           |  
|                                                         | Total operating revenues |                             |       | 215.1                     |  
|Fuel and plant operations                                |                          |                             | 181.9 |                           |  
|Depreciation and amortization                            |                          |                             | 37.7  |                           |  
|                                                         |                          |                             |       |                           |  
|                                                         | Operating income (loss)  |                             | $     | (4.5                      | )
|                                                         |                          |                             |       |                           |  

Operating Revenues

Operating revenues decreased $47.9 million and $128.1 million for the second quarter and six months ended June 30, 2001, respectively,
compared to the corresponding periods of the prior year. The decrease resulted primarily from lower electric revenues from the Ferrybridge and Fiddler's Ferry plants and the First Hydro plant due to
lower energy prices and an 8.2% decrease in the average exchange rate of the pound sterling compared to the U.S. dollar at the six-month period ended June 30, 2001, compared to the
same prior year period. The time weighted average System Marginal Price decreased from £21.3/MWh during the quarter ended March 31, 2000 to £18.6/MWh during the quarter
ended March 31, 2001. 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, therefore eliminating the System Marginal Price. The new electricity trading arrangements are described in further detail under "Market Risk ExposuresUnited
Kingdom." These new electricity trading arrangements have resulted in lower forward contract prices for the quarter ended June 30, 2001, compared to the quarter ended June 30, 2000. The
First Hydro plant, Ferrybridge and Fiddler's Ferry plants and the Iberian Hy-Power plants generally provide higher electric revenues during the winter months.

Net
losses from price risk management activities were $3.9 million and $14.1 million for the second quarter and six months ended June 30, 2001, respectively.
There were no comparable gains or losses for the same prior year periods. The losses primarily represent the change in market value of electricity rate swap agreements that were recorded at fair value
under SFAS No. 133 with changes in fair value recorded through the income statement.

Equity
in income from investments increased $5.9 million and $4 million during the second quarter and six months ended June 30, 2001, respectively, compared to
the same prior year periods. The increase reflects lower losses during the second quarter ended June 30, 2001, compared to the corresponding period in 2000 from the ISAB project, which
commenced operations in April 2000. We had no comparable results for the ISAB project in the first quarter of 2000.

Operating Expenses

Fuel and plant operations increased $25.5 million for the quarter ended June 30, 2001, compared to the corresponding period in 2000. The increase
in fuel expense resulted from higher fuel costs at the Doga plant due to increased production in the second quarter of 2001, compared to the same prior year quarter, when the plant experienced more
unplanned outages. In addition, fuel costs increased at the First Hydro plant due to higher overnight prices and imbalance charges. The increase in plant

23

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operations resulted primarily from higher overhaul costs at the Ferrybridge and Fiddler's Ferry plants during the quarter ended June 30, 2001, compared to the corresponding period in 2000.

Fuel
and plant operations decreased $1.3 million for the six months ended June 30, 2001, compared to the same prior year period. The decrease in fuel expense and plant
operations resulted primarily from a decrease in the average exchange rate of the pound sterling compared to the U.S. dollar. In addition, plant operations decreased from lower production at the
Ferrybridge and Fiddler's Ferry plants during the first six months of 2001. Partially offsetting these decreases were higher fuel costs and plant operation expenses for the Doga plant due to increased
production in the first six months of 2001, compared to the same prior year period.

Operating Income

Operating income decreased $72.2 million and $135.2 million during the second quarter and six months ended June 30, 2001, respectively,
compared to the same prior year periods. The decrease was due to lower operating income from the Ferrybridge and Fiddler's Ferry plants, the First Hydro plant and the Doga plant.

Corporate/Other

|                                                        |                | Three Months Ended
June 30, |      | Six Months Ended
June 30, |  
|------------------------------------------------------- | -------------- | --------------------------- | ---- | ------------------------- | -
|
|
|Net gains from energy trading and price risk management |                | $                           | 0.4  |                           | $
|Depreciation and amortization                           |                |                             | 2.6  |                           |  
|Long-term incentive compensation                        |                |                             | 0.8  |                           |  
|Administrative and general                              |                |                             | 33.4 |                           |  
|                                                        |                |                             |      |                           |  
|                                                        | Operating loss |                             | $    | (36.4                     | )
|                                                        |                |                             |      |                           |  

Net
gains from price risk management activities were $0.4 million and $1.3 million for the second quarter and six months ended June 30, 2001, respectively. There
were no comparable gains or losses for the same prior year periods. The gains primarily resulted from the change in market value of our interest rate swaps with respect to our $100 million
senior notes that did not qualify for hedge accounting under SFAS No. 133.

Long-term
incentive compensation expense consists of charges related to our terminated phantom option plan. We recorded an adjustment to our long-term
incentive compensation accrual during the six months ended June 30, 2001 for changes in the market value of stock equivalent units.

Administrative
and general expenses decreased $6.3 million and $8.7 million for the second quarter and six months ended June 30, 2001, respectively, compared to
the corresponding periods of 2000. The decrease was the result of lower administrative and general operating costs.

24

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Other Income (Expense)

Interest and other income increased $5.5 million for the six months ended June 30, 2001, compared to the same prior year period. The increase was
primarily due to higher interest income and foreign exchange gains on intercompany loans. Higher interest income resulted from the $255 million of notes purchased in connection with the
sale-leaseback of the Illinois peaker power units in July 2000.

On
June 29, 2001, we completed the sale of our 25% interest in the Hopewell project to the existing partner. Proceeds from the sale were $26.5 million. We recorded a
gain on the sale of $5.4 million ($2.8 million after tax).

On
June 30, 2000, we completed the sale of our 50% interest in the Auburndale project to the existing partner. Proceeds from the sale were $22 million. We recorded a
gain on the sale of $17.0 million ($10.5 million after tax).

Interest
expense decreased $18.5 million and $37.7 million for the second quarter and six months ended June 30, 2001, respectively, compared to the same prior
year periods. The decrease was primarily the result of payment on our $500 million floating rate notes issued in December 1999 and subsequently paid in September 2000, lower
interest rates on debt financing associated with the Illinois Plants and favorable changes in foreign exchange rates.

Minority
interest expense increased $6.5 million and $6.1 million for the second quarter and six months ended June 30, 2001, respectively, compared to the same
prior year periods. The increase was due to accounting for Contact Energy on a consolidated basis, effective June 1, 2001, due to the purchase of additional shares of Contact Energy that
resulted in our ownership interest increasing from 42.6% to 51.2%.

Provision (Benefit) for Income Taxes

During the six months ended June 30, 2001, we recorded an effective tax provision rate of 39% based on projected income for the year and benefits under
our tax sharing agreement, compared to the annual effective tax benefit rate for the first six months of 2000 of 36%.

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.

Cumulative Effect of Change in Accounting Principle

Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The Statement 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. The Statement 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. The ineffective portion of a derivative's change in fair value is immediately
recognized in earnings.

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,

25

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we record all derivatives at fair value unless the derivatives qualify 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, as amended, are
met. The majority of our physical long-term power and fuel contracts, and the similar business activities of our affiliates, qualify under this exception.

The
majority of our remaining risk management activities, including forward sales contracts from our Homer City plant, qualify for treatment under SFAS No. 133 as cash flow
hedges with appropriate adjustments made to other comprehensive income. The hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project
in Australia qualifies as a cash flow hedge. This contract could not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical
delivery. Some of our derivatives did not qualify for either the normal sales and purchases exception or as cash flow hedges. These derivatives are recorded at fair value with subsequent changes in
fair value recorded through the income statement. The majority of our activities related to the Ferrybridge and Fiddler's Ferry power
plants in the United Kingdom and fuel contracts related to the Collins Station in Illinois do not qualify for either the normal purchases and sales exception or as cash flow hedges. In both these
situations, we could not conclude, based on information available at June 30, 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 are recorded at fair value, with subsequent changes in fair value reflected in net gains (losses) from energy
trading and price risk management in the consolidated income statement.

As
a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under our prior accounting policy. We recorded a
$6 million, after tax, increase to net income as the cumulative change in the accounting for derivatives during the quarter ended March 31, 2001. In addition, we recorded a
$230 million, after tax, unrealized holding loss upon adoption of a change in accounting principle reflected in accumulated other comprehensive loss in the consolidated balance sheet. During
the quarter ended June 30, 2001, we recorded a $120 million, after tax, unrealized holding gain reflected in accumulated other comprehensive loss in the consolidated balance sheet. We
recorded a loss of $0.3 million, after tax, and $7.4 million, after tax, for the quarter ended and six months ended June 30, 2001, respectively, as the change in the fair value of
derivatives required under SFAS No. 133 that previously qualified for hedge accounting. We also recorded a net gain of $1.5 million and $1.6 million for the quarter ended and six
months ended June 30, 2001, respectively, representing the amount of cash flow hedges' ineffectiveness, reflected in net gains (losses) from energy trading and price risk management in the
consolidated income statement.

The
Derivative Implementation Group of the Financial Accounting Standards Board has recently provided guidance on the normal sales and purchases exception that affects classification
on commodity contracts. We did not use the normal sales and purchases exception for forward sales contracts from our Homer City plant due to our net settlement procedures with counterparties for the
period between January 1, 2001 through June 30, 2001. Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board extended the normal
sales and purchases exception to include forward sales contracts subject to net settlement procedures with counterparties. Accordingly, we intend to use the normal sales and purchases exception for
our Homer City forward sales contracts commencing July 1, 2001 and plan to record a cumulative change in the accounting for derivatives during the quarter ended September 30, 2001. We
are currently evaluating the impact of the implementation guidance on our remaining commodity contracts, which would be accounted for on a prospective basis.

Through
December 31, 1999, we accrued for major maintenance costs incurred during the period between turnarounds (referred to as "accrue in advance" accounting method). In
March 2000, we

26

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voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is considered preferable based on guidance provided by
the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we recorded a $17.7 million, after tax, increase to net
income, as a cumulative change in the accounting for major maintenance costs during the quarter ended March 31, 2000.

Liquidity and Capital Resources

At June 30, 2001, we had cash and cash equivalents of $573.4 million and had available a total of $16 million of borrowing capacity under
one of our three revolving senior credit facilities. We had no borrowing capacity under our other two credit facilities. One of our credit facilities was originally scheduled to mature in
March 2001 but was extended twice: first to May 2001 and then to October 2001. One of our other credit facilities was originally scheduled to mature in May 2001 but was
also extended to October 2001. Currently, all three of these credit facilities are scheduled to mature on October 10, 2001. We are obligated to the lenders under our credit facilities to
repay indebtedness, and concurrently reduce the outstanding commitments under these credit facilities to $1 billion by August 15, 2001. See "Corporate Financing Plans."

In
April 2001, we issued $600 million of 9.875% senior notes, due in 2011. We used the proceeds of that offering to repay indebtedness, including mandatory repayments of
$225 million, which also permanently reduced the amount available under our credit facilities. As a result of the mandatory repayments, the credit facilities were reduced from
$1.5 billion to $1.275 billion. In connection with the sale of our 25% interest in the Hopewell project and a 50% interest in the Sunrise project, our credit facilities were further
reduced to $1.224 billion. On August 10, 2001, we issued $400 million of 10% senior notes, due in 2008. We used the proceeds to permanently repay indebtedness under our corporate
credit facilities, reducing the outstanding commitments under these facilities to $823.3 million.

Discussion of Historical Cash Flow

Net cash used in operating activities totaled $372.1 million during the six months ended June 30, 2001, compared to net cash provided by
operating activities of $68.4 million for the corresponding period of the prior year. The decrease is primarily due to higher working capital requirements. Net working capital at
June 30, 2001 was ($1,160.5) million compared to ($1,703.9) million at December 31, 2000.

Net
cash provided by financing activities decreased to $381.4 million for the six months ended June 30, 2001 from $524.6 million for the six months ended
June 30, 2000. In January 2000, one of our foreign subsidiaries borrowed $242.7 million from Edison Capital, an indirect affiliate. During the first quarter of 2001, the
subordinated financing was repaid with interest. In April 2001, we issued $600 million of 9.875% senior notes due 2011, the proceeds of which were used to permanently repay
$225 million on our corporate credit facilities. In June 2001, an additional $51 million was permanently repaid on our corporate credit facilities. In addition, dividends totaling
$65 million were paid to The Mission Group and ultimately to Edison International, our ultimate parent company, during the six-month period ended June 30, 2001, compared to
$44 million during the same prior year period. As of June 30, 2001, we had recourse debt of $2.5 billion, with an additional $6.1 billion of non-recourse debt
(debt which is recourse to specific assets or subsidiaries, but not to Edison Mission Energy) on our consolidated balance sheet.

Net
cash used in investing activities increased to $347.5 million for the six months ended June 30, 2001 from $307.6 million for the six months ended
June 30, 2000. The increase is primarily due to the equity contributions made by us to meet capital calls by partnerships who own qualifying facilities that have power purchase agreements with
Southern California Edison and Pacific Gas and Electric during

27

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the six-month period ended June 30, 2001. See "The California Power Crisis and Our Response" for further discussion. Through June 30, 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. Through June 30, 2000, $27 million was paid towards the purchase price and $13 million
in equity contributions for the Italian Wind Projects and $33.5 million was made in equity contributions for the EcoEléctrica project. In June 2001, we also completed the
sale of a 50% interest in the Sunrise project to Texaco for $84 million. We invested $113.2 million and $178.5 million during the six-month period ended
June 30, 2001 and 2000, respectively, in new plant equipment principally related to the Homer City plant and Illinois Plants.

Corporate Financing Plans

As discussed above, we have three corporate credit facilities scheduled to expire on October 10, 2001 with an aggregate amount of commitments of
$1.224 billion thereunder as of June 30, 2001, which we have committed to reduce to $1 billion in the aggregate by August 15, 2001. Our corporate cash requirements in 2001
are expected to exceed cash distributions from our subsidiaries. In addition to the commitment to pay down the corporate credit facilities by $224 million, our expected corporate cash payments
for the remainder of 2001 include:



We
used the proceeds from the August 2001 offering of senior notes to pay down a portion of our existing corporate credit facilities. In addition, we have selected a syndicate
of bank lenders to implement a new $750 million credit facility. We plan to use this new facility, together with other corporate funds, to replace the balance under our existing corporate
credit facilities. Completion of this new credit facility is subject to a number of conditions. Although we believe our corporate financing plans will be successful in meeting our cash and credit
requirements in 2001, no assurance can be provided that we will be able to obtain new financing to meet our obligations under our corporate credit facilities in 2001, or if we were able to obtain new
financing, that the new financing would be on similar terms and rates as our existing credit facilities, on commercially reasonable terms or on the terms required by the Mission Energy Holding
financing documents.

In
addition, we:



In
addition to our obligation to reduce our credit facilities to $1 billion in the aggregate under the credit facilities, we are also required to use 50% of the net proceeds
from the sale of assets and 100% of the net proceeds from our issuance of capital markets debt to repay senior bank indebtedness until

28

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the aggregate commitment amount under our existing credit facilities is further reduced to $850 million. In this regard, we may incur additional federal and state income taxes from the proceeds
of the sale of one of our foreign projects if the sale of this project is completed and we are required to repatriate funds to reduce senior bank indebtedness. There is no assurance that we will be
able to sell projects on favorable terms or that the sale of individual projects will not result in a loss. We are also considering sale-leaseback transactions of certain projects, the
proceeds of which would be used to repay short-term indebtedness or to meet other capital requirements.

Subsidiary Financing Plans

The estimated capital expenditures of our subsidiaries for the second half of 2001 are $117 million, including environmental expenditures disclosed
under "Environmental Matters and Regulations." These capital expenditures are planned to be financed by existing subsidiary credit agreements and cash generated from their operations.
Other than as described under "Commitments and Contingencies," we do not plan to make additional capital contributions to our subsidiaries.

Purchase of Additional Shares in Contact Energy

During the second quarter of 2001, we completed the purchase of additional shares of Contact Energy for NZ$152 million, thereby increasing our ownership
interest from 42.6% to 51.2%. In order to finance this purchase, we obtained a NZ$135 million, 364-day bridge loan from an investment bank under a credit facility which is to be
syndicated by the bank. In addition to other security arrangements, a security interest over all Contact Energy shares held has been provided as collateral. In June and July 2001, we issued
through one of our subsidiaries new preferred securities to repay the bridge loan. On July 2, 2001, we redeemed NZ$400 million EME Taupo preferred securities from the existing holders.
Funding for the redemption of the existing preferred securities was provided by a NZ$400 million credit facility scheduled to mature in July 2005. The financing documents governing the
credit facility provide that the credit facility may be funded under either, or a combination of, a letter of credit facility or a revolving credit facility. The NZ$400 million was originally
funded as a revolving credit facility.

Status of Edison First Power Loan

The financial performance of the Fiddler's Ferry and Ferrybridge power plants has not met our expectations, largely due to lower energy power prices resulting
primarily from increased competition, milder winter weather and uncertainty surrounding the new electricity trading arrangements. See "Market Risk ExposuresUnited Kingdom."
As a result, Edison First Power has defaulted on its financing documents related to the acquisition of the power plants. As a result of the reduced financial performance, Edison First Power deferred
some environmental capital expenditure milestone requirements in the original capital expenditure program set forth in the financing documents. The original capital expenditure program has been
revised, and this revision has been agreed to by the financing parties. In addition, in July 2001, the financing parties waived technical defaults under the financing documents and a default
under the financing documents resulting from the fact that, due to this reduced financial performance, Edison First Power's debt service coverage ratio during 2000 declined below the threshold set
forth in the financing documents. There is no assurance that Edison First Power's creditors will continue to waive its non-compliance with the requirements under the financing documents or
that Edison First Power will satisfy its financial ratios in the future.

The
financing documents stipulate that a breach of the financial ratio covenant constitutes an immediate event of default and, if the event of default is not waived, the financing
parties are entitled
to enforce their security over Edison First Power's assets, including the Fiddler's Ferry and Ferrybridge plants. Despite the breaches under the financing documents, Edison First Power's debt service
coverage ratio for 2000 exceeded 1:1. Due to the timing of its cash flows and debt service payments, Edison First

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Power utilized £37 million from its debt service reserve to meet its debt service requirements in 2000. In March 2001, £61 million was paid by Edison First
Power to meet its semi-annual debt service requirements.

Another
of our subsidiaries, EME Finance UK Limited, is the borrower under the facility made available for the purposes of funding coal and capital expenditures related to the
Fiddler's Ferry and Ferrybridge power plants. At June 30, 2001, £58 million was outstanding for coal purchases and zero was outstanding to fund capital expenditures under
this facility. EME Finance UK Limited on-lends any drawings under this facility to Edison First Power. The financing parties of this facility have also issued letters of credit directly to
Edison First Power to support their obligations to lend to EME Finance UK Limited. EME Finance UK Limited's obligations under this facility are separate and apart from the obligations of
Edison First Power under the financing documents related to the acquisition of these plants. We have guaranteed the obligations of EME Finance UK Limited under this facility, including any
letters of credit issued to Edison First Power under the facility, for the amount of £359 million, and Edison Mission Energy's guarantee remains in force notwithstanding any
breaches under Edison First Power's acquisition financing documents.

In
accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed," we have evaluated
impairment of the Ferrybridge and Fiddler's Ferry power plants. The undiscounted projected cash flow from these power plants exceeds the net book value at December 31, 2000, and, accordingly,
no impairment of these power plants is permitted under SFAS No. 121. As a result of the change in the prices of power in the U.K., we are offering for sale through a competitive bidding process
the Ferrybridge and Fiddler's Ferry power plants. Management has not made a decision whether or not the sale of these power plants will ultimately occur and, accordingly, these assets are not
classified as held for sale. If we are successful at selling the Ferrybridge and Fiddler's Ferry plants, it is likely that we will not recover any of our investment in the subsidiary that owns these
assets. At June 30, 2001, that investment was $974 million. We plan to use the proceeds from the sale, if it occurs, to repay a portion or all of the indebtedness of the project. There
is no assurance that acceptable bids will be obtained or, if such bids are acceptable, that completion of the sale will occur. In this regard, there is no assurance that we will be able to negotiate
acceptable terms and conditions with a potential buyer or that if an agreement was reached, that we will be able to satisfy the conditions needed for closing, which will include, among other things, a
regulatory review in the United Kingdom.

Limitations on Dividends from the Doga Project

Our subsidiary, Doga Enerji, owns 80% of the Doga project in Turkey. Doga Enerji has experienced delays in receiving payments from its power purchaser Turkiye
Elektrik, A.S., also referred to as TEAS. Doga Enerji is in the process of determining whether these delays will materially adversely affect the future cash flow projections for the project. Until
such determination is made, Doga Enerji will not make a distribution for 2001. While such payment obligations are guaranteed by the Turkish Treasury, we cannot assure you that TEAS will make its
payments on a timely basis.

Intercompany Tax Sharing Payments

We participate in a tax sharing agreement with The Mission Group, which in turn participates in a tax sharing agreement with Edison International. We have
historically received tax payments under the tax sharing agreement related to domestic net operating losses incurred by us. However, we will be required to pay Edison International $51 million
during 2001 as a result of changes in estimated taxable income for 2000. At June 30, 2001, we have recorded $142.5 million as an income tax receivable under the tax sharing agreement.
However, we are not eligible to receive tax sharing payments for such losses until such time as Edison International and its subsidiaries generate sufficient

30

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taxable income in order to be able to monetize tax losses of Edison Mission Energy in the consolidated income tax returns for Edison International and its subsidiaries.

Credit Ratings

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



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

A
downgrade in our credit ratings could increase our cost of capital, increase our credit support obligations, make efforts to raise capital more difficult and could have an adverse
impact on us and our subsidiaries.

Restricted Assets of 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
may not be available to satisfy our obligations or the obligations of any of our other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to
applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or to an affiliate of ours.

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Commitments and Contingencies

Capital Commitments

The following table summarizes our consolidated capital commitments as of June 30, 2001. Details regarding these capital commitments are discussed in
the sections referenced.

|Type of Commitment                                     |  | Estimated
Cost in U.S. $ |  | Time
Period |  | Discussed Under                                                                                                                                          
|------------------------------------------------------ |  | ------------------------ |  | ----------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------
|
|New Gas-Fired Generation                               |  | $250                     |  | by 2003     |  | Illinois PlantsPower Purchase Agreements, included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2000 
|New Gas-Fired Generation                               |  | 986*                     |  | 2001-2004   |  | Edison Mission Energy Master Turbine Lease, included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2000
|Environmental Improvements at our Project Subsidiaries |  | 494                      |  | 2001-2005   |  | Environmental Matters and Regulations                                                                                                                    
|Project Acquisition for the Italian Wind Projects      |  | 8                        |  | 2001-2002   |  | Firm Commitment for Asset Purchase                                                                                                                       
|Equity Contribution for the Sunrise Project            |  | 123                      |  | 2001-2003   |  | Firm Commitments to Contribute Project Equity                                                                                                            
|Equity Contribution for the Italian Wind Projects      |  | 1                        |  | 2001-2002   |  | Firm Commitments to Contribute Project Equity                                                                                                            
|Equity Contribution for the CBK Project                |  | 59                       |  | 2003        |  | Firm Commitments to Contribute Project Equity                                                                                                            

---

Firm Commitment for Asset Purchase

Project

Local Currency

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

18 billion Italian Lira

$
7.9


---

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Firm Commitments to Contribute Project Equity

Projects

Local Currency

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

3 billion Italian Lira

$
1.4CBK Project(ii)




58.5Sunrise Project(iii)




122.9


---

Firm
commitments to contribute project equity could be accelerated due to events of default as defined in the non-recourse project financing facilities. Management does
not believe that these events of default will occur to require acceleration of the firm commitments.

Other Commitments

Homer City

Edison Mission Energy has guaranteed to the bondholders, banks and other secured parties that financed the acquisition of the Homer City plant the performance
and payment when due by Edison Mission Holdings Co. of its obligations in respect of specified senior debt, up to $42 million. This guarantee will be available until December 31, 2001,
after which time Edison Mission Energy will have no further obligations under this guarantee. To satisfy the requirements under the Edison Mission Holdings Co. bank financing to have a debt service
reserve account balance in an amount equal to six months' debt service, Edison Mission Energy provides a guarantee of Edison Mission Holdings' obligations in the amount of $9 million to the
lenders involved in the bank financing.

Credit Support for Trading and Price Risk Management Activities

Our 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 us. The majority of Edison Mission Marketing & Trading's contracts have various standards of creditworthiness, including the maintenance of specified credit ratings. If Edison
Mission Marketing & Trading does not maintain its investment grade rating or if other events adversely affect its financial position, a third party could request Edison Mission
Marketing & Trading to provide adequate assurance. Adequate assurance could take the form of supplying additional

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financial information, additional guarantees, collateral, letters of credit or cash. Failure to provide adequate assurance could result in a counterparty liquidating an open position and filing a
claim against Edison Mission Marketing & Trading for any losses.

The
California power crisis has adversely affected the liquidity of West Coast trading markets and, to a lesser extent, other regions in the United States. Our trading and price risk
management activity has been reduced as a result of these market conditions and uncertainty regarding the effect of the power crisis on our affiliate, Southern California Edison. It is not certain
that resolution of the California power crisis will occur in 2001 or that, if resolved, we will be able to conduct trading and price risk management activities in a manner that will be favorable to
us.

Subsidiary Indemnification Agreements

Some of our subsidiaries have entered into indemnification agreements, under which the subsidiaries have 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, 2001, if payment were required, would be $246 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.

Other

In support of the businesses of our subsidiaries, we have made, from time to time, guarantees, and have entered into indemnity agreements with respect to our
subsidiaries' obligations like those for debt service, fuel supply or the delivery of power, and have entered into reimbursement agreements with respect to letters of credit issued to third parties to
support our subsidiaries' obligations. We may incur additional guaranty, indemnification, and reimbursement obligations, as well as obligations to make equity and other contributions to projects in
the future.

Contingencies

The California Power Crisis

In the past year, various market conditions and other factors have resulted in higher wholesale power prices to California utilities. At the same time, two of
the three major California utilities, Southern California Edison and Pacific Gas and Electric, have operated under a retail rate freeze. As a result, there has been a significant under recovery of
costs by Southern California Edison and Pacific Gas and Electric, and each of these companies has failed to make payments due to power suppliers, including us, and others. Given these and other
payment defaults, Southern California Edison could face bankruptcy at any time. Pacific Gas and Electric filed a voluntary bankruptcy petition on April 6, 2001. Edison International, our
ultimate parent company, is also the corporate parent of Southern California Edison. For a description of this contingency and the California power crisis, see "The California Power
Crisis and Our Response."

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. Our investment in the Paiton project was $503 million at June 30, 2001. Paiton Energy is in continuing negotiations on a
long-term restructuring of the tariff under a long-term power purchase agreement with the state-owned electric utility company, PT PLN. Paiton Energy and PT PLN agreed on a
Phase I Agreement for the period from January 1, 2001 through June 30, 2001. This agreement provided for fixed monthly payments aggregating $108 million over its
six-month duration and for the payment for

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energy delivered to PT PLN from the plant during this period. PT PLN made all fixed payments due under the Phase I Agreement totaling $108 million as scheduled. Paiton Energy received lender
approval of the Phase I Agreement, and Paiton Energy has also entered into a lender interim agreement under which lenders have effectively agreed to interest-only payments and to deferral
of principal payments while Paiton Energy and PT PLN seek a long-term restructuring of the tariff. The lenders have agreed to extend that agreement through December 31, 2001. Paiton
Energy and PT PLN intended to complete the negotiations of the future phases of a new long-term tariff during the six-month duration of the Phase I Agreement. Although Paiton
Energy and PT PLN did not complete negotiations on a long-term restructuring of the tariff by June 30, 2001, Paiton Energy and PT PLN have signed an agreement providing for an
extension of the Phase I Agreement from July 1, 2001 to September 30, 2001. Paiton Energy is continuing to generate electricity to meet the power demand in the region and believes that
PT PLN will continue to agree to make payments for electricity on an interim basis beyond June 30, 2001 while negotiations regarding the long-term restructuring of the tariff
continue. Although completion of negotiations may be delayed, Paiton Energy continues to believe that negotiations on the long-term restructuring of the tariff will be successful. For a
more detailed discussion of the restructuring of the tariff and related matters, refer to "Commitments and ContingenciesPaiton" in Item 7. of Edison Mission Energy's Annual Report on
Form 10-K for the fiscal year ended December 31, 2000.

Any
material modifications of the power purchase agreement resulting from the continuing negotiation of a new long-term tariff could require a renegotiation of the Paiton
project's debt agreements. The impact of any such renegotiations with PT PLN, the Government of Indonesia or the project's creditors on our expected return on our investment in Paiton Energy is
uncertain at this time; however, we believe that we will ultimately recover our investment in the project.

Brooklyn Navy Yard

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

Contingent Obligations to Contribute Project Equity

Projects

Local Currency

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



$
5.3ISAB(ii)

84 billion Italian Lira


36.5


---

35

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For
more information on the Paiton project, see "Paiton" above.

We
are not aware of any other significant contingent obligations or obligations to contribute project equity other than as noted above and equity contributions to be made by us to
meet capital calls by partnerships who own qualifying facilities that have power purchase agreements with Southern California Edison and Pacific Gas and Electric. See "The California
Power Crisis and Our Response" for further discussion.

The California Power Crisis and Our Response

The California Power Crisis

We have partnership interests in eight partnerships that own power plants in California and have power purchase contracts with Pacific Gas and Electric and/or
Southern California Edison. Three of these partnerships have a contract with Southern California Edison, four of them have a contract with Pacific Gas and Electric, and one of them has contracts with
both. In 2000, our share of earnings before taxes from these partnerships was $168 million, which represented 20% of our operating income. Our investment in these partnerships at
June 30, 2001 was $607 million.

As
a result of Southern California Edison's and Pacific Gas and Electric's current liquidity crisis, each of these utilities has failed to make payments to qualifying facilities
supplying them power. These qualifying facilities include the eight power plants that are owned by partnerships in which we have a partnership interest. Southern California Edison has not paid a
substantial majority of the amount due to the partnerships for power delivered between November 1, 2000 and March 26, 2001; however, in response to the March 27, 2001 California
Public Utilities Commission order discussed below, Southern California Edison has been paying the partnerships for power delivered after March 27, 2001. It is possible that Southern California
Edison may miss future payments. At June 30, 2001, accounts receivable due to these partnerships from Southern California Edison were $606 million. Our share of these receivables was
$301 million.

On
April 6, 2001, Pacific Gas and Electric filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code in San Francisco bankruptcy court. Pacific Gas and
Electric made its January payment in full and has paid for power delivered after April 6, 2001, but paid only a small portion of the amounts due to the partnerships in February and March and,
as discussed below, may not pay all or a portion of its future payments. Although Pacific Gas and Electric has thus far paid for post-petition deliveries, future payments by Pacific Gas
and Electric to the qualifying facilities, including those owned by partnerships in which we have a partnership interest, may be subject to significant delays associated with the bankruptcy court
process and may not be paid in full. Furthermore, Pacific Gas and Electric's power purchase agreements with the qualifying facilities will be subject to review by the bankruptcy court. At the petition
date, accounts receivable to these partnerships from Pacific Gas and Electric were $47 million. Our share of these receivables was $23 million. We cannot assure you that the partnerships
with long-term contracts with Pacific Gas and Electric will not be adversely affected by the bankruptcy proceeding.

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The California utilities' failure to pay has adversely affected the operations of our eight California qualifying facilities. Continuing failures to pay similarly could have an
adverse impact on the operations of our California qualifying facilities. Provisions in the partnership agreements stipulate that partnership actions concerning contracts with affiliates are to be
taken through the non-affiliated partner in the partnership. Therefore, partnership actions concerning the enforcement of rights under each qualifying facility's power purchase agreement
with Southern California Edison in response to Southern California Edison's suspension of payments under that power purchase agreement are to be taken through the non-Edison Mission Energy
affiliated partner in the partnership. During the period in which Southern California Edison failed to make payments, some of the partnerships sought to minimize their exposure to Southern California
Edison by reducing deliveries under their power purchase agreements. Four of the partnerships have filed complaints against Southern California Edison with respect to the payment defaults.

All
of those partnerships have entered into agreements with Southern California Edison, under which the partnerships and Southern California Edison will suspend the current litigation
for a specified "standstill period" and provisionally stipulate as to the amount of past due payments, and Southern California Edison will make partial payments with respect to past due amounts. The
partial payments are to be made on the following schedule: 10% of the past due amount to be paid within three business days after signing the agreements, a second 10% to be paid upon the effective
date of legislation that restores Southern California Edison to creditworthiness and enables it to pay its debts in a timely manner, and the final 80% on the fifth business day after the first day on
which Southern California Edison receives proceeds from the first financing of the "net undercollected amount" resulting from such legislation. The agreements also require Southern California Edison
to make monthly interest payments on past due amounts.

It
is unclear at this time what additional actions, if any, the partnerships will take in regard to any future suspension of payments due to the qualifying facilities by the utilities
or in the event that the settlement agreements cease to be in effect. As a result of the utilities' failure to make payments due under these power purchase agreements, the partnerships have called on
the partners to provide additional capital to fund operating costs of the power plants. From January 1, 2001 to June 30, 2001, subsidiaries of ours have made equity contributions
totaling approximately $134 million to meet capital calls by the partnerships. Although Southern California Edison has been paying the partnerships for power delivered after March 27,
2001 and Pacific Gas and Electric has paid for power delivered after April 6, 2001, our subsidiaries and the other partners may be required to make additional capital contributions to the
partnerships if the utilities fail to make future payments.

Southern
California Edison has stated that it is attempting to avoid bankruptcy and, subject to the outcome of regulatory and legal proceedings and negotiations regarding purchased
power costs, it intends to pay all its obligations once a permanent solution to the current energy and liquidity crisis has been reached. However, it is possible that Southern California Edison will
not pay all its obligations in
full. In addition, it is possible that creditors of Southern California Edison could file an involuntary bankruptcy petition against Southern California Edison. If this were to occur, payments to the
qualifying facilities, including those owned by partnerships in which we have a partnership interest, could be subject to significant delays associated with the lengthy bankruptcy court process and
may not be paid in full. Furthermore, Southern California Edison's power purchase agreements with the qualifying facilities could be subject to review by a bankruptcy court.

While
we believe that the generation of electricity by the qualifying facilities, including those owned by partnerships in which we have a partnership interest, is needed to meet
California's power needs, we cannot assure you that these settlement agreements will continue to be effective during the standstill period, or that the power purchase agreements will not be adversely
affected by a bankruptcy or any further contract renegotiation as a result of the current power crisis.

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On March 27, 2001, the California Public Utilities Commission issued a decision that ordered the three California investor-owned utilities, including Southern California Edison
and Pacific Gas and Electric, to commence payment for power generated from qualifying facilities beginning in April 2001. As a result of this decision, Southern California Edison paid in full
for power delivered after March 27, 2001, and Pacific Gas and Electric paid for power delivered after April 6, 2001 (the date it filed its bankruptcy petition). This decision did not
address payment to the qualifying facilities for amounts due prior to March 27, 2001. In addition, the decision modified the pricing formula for determining short-run avoided costs
for qualifying facilities subject to these provisions. Depending on the utilities' continued reaction to this order, the impact of this decision may be that the qualifying facilities subject to this
pricing adjustment will be paid at significantly reduced prices for their power. Furthermore, this decision called for further study of the pricing formula tied to short-run avoided costs
and, accordingly, may be subject to more changes in the future. Finally, this decision is subject to challenge before the Commission, the Federal Energy Regulatory Commission and, potentially, state
or federal courts. Although it is premature to assess the full effect of this decision, it could have a material adverse effect on our investment in the California partnerships, depending on how it is
implemented and future changes in the relationship between the pricing formula and the actual cost of natural gas procured by our California partnerships.

As
previously disclosed by Edison International, on April 9, 2001, Edison International and Southern California Edison signed a Memorandum of Understanding with the California
Department of Water Resources. The Memorandum calls for legislation, regulatory action and definitive agreements to resolve important aspects of the energy crisis, and which the parties expect will
help restore Southern California Edison's creditworthiness and liquidity. Edison International filed a Form 8-K on April 10, 2001, which describes key elements of the
Memorandum. Among other things, the Memorandum provides that we will execute a contract with the Department of Water Resources or another state agency for the provision of power from the Sunrise
project to the State at cost-based rates for ten years. We executed this contract on June 25, 2001, and the first phase became operational on June 27, 2001.

Edison
International and Southern California Edison believe that execution of the Memorandum was an important step toward an acceptable resolution of the major issues affecting Edison
International and Southern California Edison as a result of the California energy crisis, but this result is not assured. The parties agreed in the Memorandum that each of its elements is part of an
integrated package, and effectuation of each element will depend upon effectuation of the others. To implement the Memorandum, numerous actions must be taken by the parties and by other agencies of
the State of California. Southern California Edison, Edison International and the Department of Water Resources committed to proceed in good faith to sponsor and support the required legislation and
to negotiate in good faith the necessary definitive agreements. However, the California Legislature, the California Public Utilities Commission, the Federal Energy Regulatory Commission, and other
governmental entities on whose part action will be necessary to implement the Memorandum are not parties to the Memorandum. Furthermore, the Memorandum may be terminated by either Southern California
Edison or the California Department of Water Resources at any time because required regulatory actions were not taken before the applicable deadline, but neither party has terminated the Memorandum.
It is unlikely that the required legislation will be enacted before the applicable deadline. Further action on a solution to Southern California Edison's financial crisis is not expected before
August 20, 2001, when the California Legislature returns from its summer recess. A number of alternatives to the Memorandum have been proposed in the California Legislature, some of which would
not be effective in restoring the creditworthiness of Southern California Edison. Whether the Memorandum or any acceptable alternative to the Memorandum will be enacted is unknown. In addition, a
California voter initiative or referendum previously has been threatened against any measures that would raise consumer rates or aid California's investor-owned utilities. Finally, execution

38

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of the Memorandum does not eliminate the possibility that some of Southern California Edison's creditors could take steps to force Southern California Edison into bankruptcy proceedings.

On
April 3, 2001, the California Public Utilities Commission adopted an order instituting investigation. The order reopens past Commission decisions authorizing the California
investor-owned utilities to form holding companies and initiates an investigation into: whether the holding companies violated requirements to give priority to the capital needs of their respective
utility subsidiaries; whether ring-fencing actions by Edison International and PG&E Corporation and their respective non-utility affiliates (including us) also violated
requirements to give priority to the capital needs of their utility subsidiaries; whether the payment of dividends by the utilities violated requirements that the utilities maintain dividend policies
as though they were comparable stand-alone utility companies; any additional suspected violations of laws or Commission rules and decisions; and whether additional rules, conditions, or other changes
to the holding company decisions are necessary. The Memorandum calls for the Commission to adopt a decision clarifying that the first priority condition in Southern California Edison's holding company
decision refers to equity investment, not working capital for operating costs. On June 6, 2001, in response to motions filed by the three holding companies (including Edison International) to
dismiss the investigation for lack of subject matter jurisdiction, the Commission issued for comment a draft decision, which concludes, among other matters, that applicable law permits the Commission,
even if the normal common law prerequisites for piercing the corporate structures are absent, to disregard the corporate forms within the holding company system "to reach the assets of or challenge
the behaviors of entities within the holding company system" in order to protect ratepayers. Commissioner Henry Duque has issued a draft alternate decision that would grant the three holding
companies' motions to dismiss the order as to themselves, finding lack of subject matter jurisdiction over them, and would direct the Commission's general counsel to file an action in state court to
enforce the holding company conditions, if necessary. The alternate, as well as the draft decision that would deny the motions to dismiss, are presently on the Commission's agenda for its
August 23 meeting. Either would require a vote of three out of five commissioners in order to be adopted. We are not a party to this investigatory proceeding. We cannot predict whether, when or
in what form this order will be adopted, or what direct or indirect effects any subsequent action taken by the Commission in such proceeding or in any other action or proceeding, in reliance on the
principles articulated in this order and in other applicable authority, may have on Edison International or on us and our subsidiaries.

A
number of federal and state, legislative and regulatory initiatives addressing the issues of the California electric power industry have been proposed, including wholesale rate
caps, retail rate increases, acceleration of power plant permitting and state entry into the power market. Many of these activities are ongoing. For example, on March 27, 2001, the California
Public Utilities Commission made permanent the interim surcharge on customers' bills that it authorized on January 4, 2001 and authorized a rate increase of three cents per
kilowatt-hour; neither this interim surcharge nor the rate increase affected the retail rate freeze which has been in effect since deregulation began in 1998. On April 26, 2001, the
Federal Energy Regulatory Commission ordered price mitigation measures, or price caps, for power sales in the California spot market during emergency periods only; on June 19, 2001, the price
mitigation measures were expanded to apply during all periods and to cover the entire eleven-state Western region. After extensive settlement negotiations failed to produce a global settlement, on
July 25, 2001 the Federal Energy Regulatory Commission ordered that refunds may be due from sellers who engaged in transactions in these markets from October 2, 2000 through
June 20, 2001, at levels in excess of the requirements in the April 26 and July 19 orders (with certain modifications), and ordered an evidentiary hearing to determine the
required refunds. A separate proceeding was also instituted to evaluate the potential for refunds in the Pacific Northwest. The price mitigation measures end on September 30, 2002. The federal
and state, legislative and regulatory initiatives may result in a restructuring of the California power market. At this time, it is not possible to estimate the likely ultimate outcome of these
activities.

39

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Our Response

To isolate ourselves from the credit downgrades and potential bankruptcies of 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 in spite of the
current credit difficulties of Edison International, Southern California Edison and their subsidiaries. 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:





We
cannot assure you that these measures will effectively isolate us from the credit downgrades or the potential bankruptcies of Edison International, Southern California Edison or
any of their subsidiaries. In January 2001, after we implemented the ring-fencing amendments, Standard & Poor's and Moody's lowered our credit ratings. Our senior unsecured
credit ratings were downgraded to "BBB-" from "A-" by Standard & Poor's and to "Baa3" from "Baa1" by Moody's. Our credit ratings remain investment grade. Both Standard & Poor's and
Moody's have indicated that the credit ratings outlook for us is stable. However, as a result of the downgrades, our cost of capital has increased. Future downgrades could further increase our cost of
capital, increase our credit support obligations, make efforts to raise capital more difficult and could have an adverse impact on us and our subsidiaries. The measures described above are intended to
insure that we are considered a stand-alone entity. However, in the event of a bankruptcy of Mission Energy Holding, creditors of Mission Energy Holding might seek to have a bankruptcy court
substantially consolidate the assets and liabilities of us with those of Mission Energy Holding.

Market Risk Exposures

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

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Commodity Price Risk

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 plant, to the Pennsylvania-New Jersey-Maryland Power Pool (PJM) or the New York Independent System Operator
(NYISO). We have developed risk management policies and procedures, which, among other things, address credit risk. When making sales under negotiated bilateral contracts, it is our policy to deal
with investment grade counterparties or counterparties that provide equivalent credit support. Our Risk Management Committee grants exceptions to the policy only after thorough review and scrutiny.
Most entities that have received exceptions are organized power pools and quasi-governmental agencies. We hedge a portion of the electric output of our merchant plants, whose output is not committed
to be sold under long-term contracts, in order to lock in desirable outcomes. 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.

Americas

On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our trading operations
beyond the traditional marketing of our electric power. Our energy trading and price risk management activities give rise to market risk, which represents the potential loss that can be caused by a
change in the market value of a particular commitment. Market risks are actively monitored to ensure compliance with our risk management policies. Policies are in place that limit the amount of total
net exposure we may enter into at any point in time. Procedures exist that 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 reasons for 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 industry "best practice" techniques including the use of stress testing and
worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits.

Electric
power generated at the Homer City plant 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 plant is situated in the PJM control area and
is physically connected to high-voltage transmission lines serving both the PJM and NYISO markets. The Homer City plant can also transmit power to the Midwestern United States.

Electric
power generated at the Illinois Plants is sold under three power purchase agreements with Exelon Generation Company, in which Exelon Generation purchases capacity and has the
right to purchase energy generated by the Illinois Plants. The agreements, which began on December 15, 1999 and have a term of up to five years, provide for capacity and energy payments. Exelon
Generation is obligated to make a capacity payment for the plants under contract and an energy payment for the electricity produced by these plants and taken by Exelon Generation. The capacity
payments provide the Illinois Plants revenue for fixed charges, and the energy payments compensate the Illinois Plants for variable costs of production. Exelon Generation has the option to terminate
two of the three agreements in their entirety or with respect to any generating unit or units in each of 2002, 2003 and 2004. In June 2001, Exelon Generation provided us notice to continue the
agreement related to the coal units for 2002. If Exelon Generation does not fully dispatch the plants under contract, the Illinois Plants may sell, subject to specified conditions, the excess energy
at market prices to neighboring utilities, municipalities, third-party electric retailers, large consumers and power marketers on a spot

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basis. A bilateral trading infrastructure already exists with access to the Mid-America Interconnected Network and the East Central Area Reliability Council.

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 with a bilateral physical trading system referred
to as the new electricity trading arrangements.

The
new electricity trading arrangements provide for, among other things, the establishment of a spot market or voluntary short-term power exchanges operating from a year
or more in advance to 31/2-hours before a trading period of 1/2 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. Contracting over time periods longer than the day-ahead market is not directly affected by the proposals. Physical bilateral
contracts have replaced the prior financial contracts for differences, but function in a similar manner. However, it remains difficult to evaluate the future impact of the new electricity trading
arrangement. 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, against their contracted
positions or face assessment of energy imbalance penalty charges by the system operator. A consequence of this should be to increase greatly the motivation of parties to contract in advance and
develop forwards and futures markets of greater liquidity than at present. Recent experience has been that the new electricity trading arrangements have placed a significant downward pressure on
forward contract prices. Furthermore, another consequence may be that counterparties may require additional credit support, including parent company guarantees or letters of credit. Legislation in the
form of the
Utilities Act, which was approved July 28, 2000, provided for the implementation of the new electricity trading arrangements and the necessary amendments to generators' licenses.

The
legislation providing for the implementation of the new arrangements, the Utilities Act 2000, sets 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. But this is qualified by a recognition that license holders
should be able to finance their activities. The Act 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 will be
monitoring the operation of these new provisions. See "Liquidity and Capital Resources."

Asia Pacific

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

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Hedge. Additionally, the Loy Yang B plant entered into a number of fixed forward electricity contracts commencing either in 2001 or 2002, which expire on various dates through December 31,
2002, and which will further mitigate against the price volatility of the electricity pool.

New Zealand.The New Zealand Government has been undergoing a steady process of electric industry deregulation since
1987. Reform in the distribution and retail supply sector began in 1992 with legislation that deregulated electricity distribution and provided for competition in the retail electric supply function.
The New Zealand Energy Market, established in 1996, is a voluntary competitive wholesale market that allows for the trading of physical electricity on a half-hourly basis. The Electricity
Industry Reform Act, which was passed in July 1998, was designed to increase competition at the wholesale generation level by splitting up Electricity Company of New Zealand Limited, the large
state-
owned generator, into three separate generation companies. The Electricity Industry Reform Act also prohibits the ownership of both generation and distribution assets by the same entity.

The
New Zealand Government commissioned an inquiry into the electricity industry in February 2000. This Inquiry Board's report was presented to the government in mid 2000. The
main focus of the report was on the monopoly segments of the industry, transmission and distribution, with substantial limitations being recommended in the way in which these segments price their
services in order to limit their monopoly power. Recommendations were also made with respect to the retail customer in order to reduce barriers to customers switching. In addition, the Board made
recommendations in relation to the wholesale market's governance arrangements with the purpose of streamlining them. The recommended changes are now being progressively implemented.

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 or other hedging mechanisms for a number of our project financings. Interest expense included
$9.3 million and $9.6 million of additional interest expense for the six months ended June 30, 2001 and 2000, 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 $819.8 million consisting of commercial paper and bank borrowings at June 30, 2001. The fair values of these obligations
approximated their carrying values at June 30, 2001, and would not have been materially affected by changes in market interest rates. The fair market value 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 $7.7 billion at June 30,
2001.

Foreign Exchange Rate Risk

Fluctuations in foreign currency exchange rates can affect, on a United States dollar equivalent basis, the amount of our equity contributions to, and
distributions from, our international projects. As we continue to expand into foreign markets, fluctuations in foreign currency exchange rates can be expected to have a greater impact on our results
of operations in the future. 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 United States dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, we have used
statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. We cannot assure you, however, that fluctuations in exchange rates will be fully
offset by hedges or that currency movements and the relationship between certain macro economic variables will behave in a manner that is consistent with historical or

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forecasted relationships. Foreign exchange considerations for three major international projects, other than Paiton, which was discussed earlier, are discussed below.

The
First Hydro, Ferrybridge and Fiddler's Ferry plants in the U.K. and the Loy Yang B plant in Australia have been financed in their local currency, 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.

Foreign
currencies in the U.K., Australia and New Zealand decreased in value compared to the U.S. dollar by 6%, 8% and 9%, respectively (determined by the change in the exchange rates
from December 31, 2000 to June 30, 2001). The decrease in value of these currencies was the primary reason for the foreign currency translation loss of $101.2 million during the
first six months of 2001.

In
December 2000, we entered into foreign currency forward exchange contracts in the ordinary course of business to protect ourselves from adverse currency rate fluctuations on
anticipated foreign currency commitments. The periods of the forward exchange contracts correspond to the periods of the hedged transactions. At June 30, 2001, the outstanding notional amount
of the contracts totaled $73 million, consisting of contracts to exchange U.S. dollars to pound sterling with varying maturities ranging from July 2001 to July 2002. During the
first six months of 2001, we recognized a foreign exchange gain of approximately $36,000 related to the fuel purchases underlying the contracts that matured during the first six months of 2001.

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

Other

The electric power generated by some of our investments in domestic operating projects, excluding the Homer City plant and the Illinois Plants, is sold to
electric utilities under long-term contracts, typically with terms of 15 to 30 years. We structure our long-term contracts so that fluctuations in fuel costs will
produce similar fluctuations in electric and/or steam revenues and enter into long-term fuel supply and transportation agreements. The degree of linkage between these revenues and expenses
varies from project to project, but generally permits the projects to operate profitably under a wide array of potential price fluctuation scenarios.

Environmental Matters and Regulations

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

Typically,
environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the
necessary requirements

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can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures.

We
expect that compliance with the Clean Air Act and the regulations and revised State Implementation Plans developed as a consequence of the Act will result in increased capital
expenditures and operating expenses. For example, we expect to spend approximately $34 million for the final two quarters of 2001 and $12 million in 2002 to install upgrades to the
environmental controls at the Homer City plant to control sulfur dioxide and nitrogen oxide emissions. Similarly, we anticipate upgrades to the environmental controls at the Illinois Plants to control
nitrogen oxide emissions to result in expenditures of approximately $22 million for the final two quarters of 2001 and $386 million for the 2002-2005 period. In addition, at
the Ferrybridge and Fiddler's Ferry plants we anticipate environmental costs arising from plant modification of approximately $18 million for the final two quarters of 2001 and
$21 million for the 2002-2005 period.

We
own an indirect 50% interest in EcoEléctrica, L.P., a limited partnership, which owns and operates a liquefied natural gas import terminal and cogeneration project
at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoEléctrica a notice of violation and a compliance order alleging violations of the
federal Clean Air Act primarily related to start-up activities. Representatives of EcoEléctrica have met with the Environmental Protection Agency to discuss the notice of
violations and compliance order. To date, EcoEléctrica has not been informed of the commencement of any formal enforcement proceedings. It is premature to assess what, if any, action
will be taken by the Environmental Protection Agency.

On
November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act's "new source review"
requirements related to modifications of air emissions sources at electric generating stations located in the southern and midwestern regions of the United States. Several states have joined these
lawsuits. In addition, the United States Environmental Protection Agency has also issued administrative notices of violation alleging similar violations at additional power plants owned by some of the
same utilities named as defendants in the Department of Justice lawsuit, as well as other utilities, and also issued an administrative order to the Tennessee Valley Authority for similar violations at
certain of its power plants. The Environmental Protection Agency has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including the prior owners
of the Homer City plant, seeking to determine whether these utilities also engaged in activities that may have been in violation of the Clean Air Act's new source review requirements.

To
date, one utility, the Tampa Electric Company, has reached a formal agreement with the United States to resolve alleged new source review violations. Two other utilities, the
Virginia Electric & Power Company and Cinergy Corp., have reached agreements in principle with the Environmental Protection Agency. In each case, the settling party has agreed to incur over
$1 billion in expenditures over several years for the installation of additional pollution control, the retirement or repowering of coal-fired generating units, supplemental
environmental projects and civil penalties. These agreements provide for a phased approach to achieving required emission reductions over the next 10 to 15 years. The settling utilities have
also agreed to pay civil penalties ranging from $3.5 million to $8.5 million.

Prior
to our purchase of the Homer City plant, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the plant.
Other than with respect to the Homer City plant, no proceedings have been initiated or requests for information issued with respect to any of our United States facilities. However, we have been in
informal voluntary discussions with the Environmental Protection Agency relating to these facilities, which may result in the payment of civil fines. We cannot assure you that we will reach a
satisfactory agreement or that these facilities will not be subject to proceedings in the future. Depending on the outcome of the proceedings, we could be required to invest in additional pollution
control requirements, over and

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above the upgrades we are planning to install, and could be subject to fines and penalties. In May 2001, President Bush issued a directive for a 90-day review of new source review
"interpretation and implementation" by the Administrator of the Environmental Protection Agency and the Secretary of the U.S. Department of Energy. President Bush also directed the Attorney General to
review ongoing new source review legal actions to "ensure" they are "consistent with the Clean Air Act and its regulations." Both actions were recommendations detailed within the Bush Administration's
"National Energy Policy Task Force Report."

A
new ambient air quality standard was adopted by the Environmental Protection Agency in July 1997 to address emissions of fine particulate matter. It is widely understood that
attainment of the fine
particulate matter standard may require reductions in nitrogen oxides and sulfur dioxides, although under the time schedule announced by the Environmental Protection Agency when the new standard was
adopted, non-attainment areas were not to have been designated until 2002 and control measures to meet the standard were not to have been identified until 2005. In May 1999, the
United States Court of Appeals for the District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act, the section of the Clean Air Act requiring the promulgation of national
ambient air quality standards, as interpreted by the Environmental Protection Agency, was an unconstitutional delegation of legislative power. The Court of Appeals remanded both the fine particulate
matter standard and the revised ozone standard to allow the EPA to determine whether it could articulate a constitutional application of Section 109(b)(1). On February 27, 2001, the
Supreme Court, inWhitman v. American Trucking Associations, Inc., reversed the Circuit Court's judgment on this issue and remanded the case back
to the Court of Appeals to dispose of any other preserved challenges to the particulate matter and ozone standards. Accordingly, as the final application of the revised particulate matter ambient air
quality standard is potentially subject to further judicial proceedings, the impact of this standard on our facilities is uncertain at this time.

On
December 20, 2000, the Environmental Protection Agency issued a regulatory finding that it is "necessary and appropriate" to regulate emissions of mercury and other
hazardous air pollutants from coal-fired power plants. The agency has added coal-fired power plants to the list of source categories under Section 112(c) of the Clean
Air Act for which "maximum available control technology" standards will be developed. Eventually, unless overturned or reconsidered, the Environmental Protection Agency will issue technology-based
standards that will apply to every coal-fired unit owned by us or our affiliates in the United States. This section of the Clean Air Act provides only for technology-based standards, and
does not permit market trading options. Until the standards are actually promulgated, the potential cost of these control technologies cannot be estimated, and we cannot evaluate the potential impact
on the operations of our facilities.

In
June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency to evaluate and issue a report to the Illinois legislature addressing the need
for further emissions controls on fossil fuel-fired electric generating stations, including the potential need for additional controls on nitrogen oxides, sulfur dioxide and mercury. The
study, which is to be submitted between September 30, 2003 and September 30, 2004, also requires an evaluation of incentives to promote renewable energy and the establishment of a
banking system for certifying credits from voluntary reductions of greenhouse gases. The law allows the Illinois Environmental Protection Agency to propose regulations based on its findings no sooner
than ninety days after the issuance of its findings, and requires the Illinois Pollution Control Board to act within one year on such proposed regulations. Until the Illinois Environmental Protection
Agency issues its findings and proposes regulations in accordance with the findings, if such regulations are proposed, we cannot evaluate the potential impact of this legislation on the operations of
our facilities.

Since
the adoption of the United Nations Framework Convention on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions. In
December 1997, the Clinton Administration participated in the Kyoto, Japan negotiations, where the basis of a Climate

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Change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7% from 1990
levels.

The
Kyoto Protocol has yet to be submitted to the U.S. Senate for ratification. In March 2001, the Bush Administration announced that the United States would not ratify the
Kyoto Protocol, but would instead offer an alternative. Various bills have been, and are expected to be, introduced in Congress to address some of these implementing guidelines and other aspects of
climate change. Apart from the Kyoto Protocol, we may be impacted by future federal or state legislation relating to controlling greenhouse gas emissions.

Notwithstanding
the Bush Administration position, in July 2001, environment ministers from around the world met in Bonn, Germany and reached a compromise agreement on the
mechanics and rules of the Kyoto Protocol. The compromise agreement is believed to clear the way for countries to begin the treaty ratification process. The United States was the sole country not to
embrace the agreement.

We
either have an equity interest in or own and operate generating plants in the following countries:

 Australia

 Spain Indonesia

 Thailand Italy

 Turkey New Zealand

 The United Kingdom Philippines

 The United States


With
the exception of Turkey, all of the countries identified have ratified the UN Framework Convention on Climate Change, as well as signed the Kyoto Protocol. None of the countries have ratified the
Kyoto Protocol, but, with the exception of the United States, all are expected to do so by the end of 2002. For the treaty to come into effect, it must be ratified by approximately 55 countries,
representing at least 55% of the greenhouse gas emissions of the developed world.

All
of the countries, with the exception of Indonesia, the Philippines and Thailand, are classified as Annex 1 or "developed" countries and are subject to national greenhouse gas
emission reduction targets during the period of 2008-2012 (e.g., Phase 1). Each nation is actively developing policies and
measures meant to assist it with meeting the individual national emission targets as set out within the Kyoto Protocol.

If
we do become subject to limitations on emissions of carbon dioxide from our fossil fuel-fired electric generating plants, these requirements could have a significant
economic impact on their operations.

The
Environmental Protection Agency proposed rules establishing standards for the location, design, construction and capacity of cooling water intake structures at new facilities,
including steam electric power plants. Under the terms of a consent decree entered into by the U.S. District Court for the Southern District of New York in Riverkeeper, Inc. v. Whitman, these
regulations must be adopted by November 9, 2001. The consent decree also requires the agency to
propose similar regulations for existing facilities by February 28, 2002, and finalize those regulations by August 28, 2003. Until the final standards are promulgated, we cannot
determine their impact on our facilities or estimate the potential cost of compliance.

The
Comprehensive Environmental Response, Compensation, and Liability Act, which is also known as CERCLA, and similar state statutes require the cleanup of sites from which there has
been a release or threatened release of hazardous substances. As of the date of this report, we are unaware of any material liabilities under CERCLA or similar state statutes; however, we cannot
assure you that we will not incur CERCLA liability or similar state law liability in the future.

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New Accounting Standards

In July 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible
Assets," which will be effective on January 1, 2002. The Statement 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.

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 or its recorded amount or incurs a gain or loss upon settlement.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a complete discussion of market risk sensitive instruments, refer to "Market Risk Exposures" in Item 7. of Edison Mission Energy's Annual Report on
Form 10-K for the fiscal year ended December 31, 2000. Refer to "Market Risk Exposures" in Item 2. for an update to that disclosure.

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PART IIOTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

|Exhibit No. |  | Description                                                                                                                                                                                                                                                                                                                                                      
|----------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.1.3       |  | Certificate of Amendment of Articles of Incorporation of Edison Mission Energy dated July 2, 2001.                                                                                                                                                                                                                                                               
|10.15.2     |  | Amendment Two to Second Amended and Restated U.S. $425 million Bank of America, N.A. Credit Agreement, dated as of May 30, 2001.                                                                                                                                                                                                                                 
|10.60.2     |  | Amendment No. 2 to the Debt Service Reserve Guarantee, dated as of March 18, 2001, made by Edison Mission Energy in favor of United States Trust Company of New York.                                                                                                                                                                                            
|10.61.2     |  | Amendment Two to Credit Agreement, dated as of March 15, 2001, by and among Edison Mission Energy, certain commercial lending institutions, and Citicorp USA, Inc., as Administrative Agent.                                                                                                                                                                     
|10.61.3     |  | Amendment Three to the U.S. $595 million Credit Agreement, dated as of May 30, 2001, by and among Edison Mission Energy, certain commercial lending institutions, and Citicorp USA, Inc., as Administrative Agent.                                                                                                                                               
|10.64.1     |  | Amendment One to Coal and Capex Facility Agreement, dated as of May 29, 2001, by and among Edison Mission Energy Finance UK Limited and Barclays Bank PLC, as Facility Agent.                                                                                                                                                                                    
|10.65.2     |  | Amendment Two to Guarantee by Edison Mission Energy Supporting the Facility Agreement, dated as of May 29, 2001.                                                                                                                                                                                                                                                 
|10.84.2     |  | Amendment Two to the U.S. $255 million Credit Agreement, dated as of May 30, 2001, by and among Edison Mission Energy, Certain Commercial Lending Institutions and Bank of America, N.A. as Administrative Agent.                                                                                                                                                
|10.91       |  | Supplemental Agreement, dated as of May 30, 2001, to Amendment Two to the Second Amended and Restated U.S. $425 million Bank of America, N.A. Credit Agreement dated as of May 30, 2001, Amendment Three to the U.S. $595 million Credit Agreement dated
as of May 30, 2001 and Amendment Two to the U.S. $255 million Credit Agreement dated as of May 30, 2001.

(b) Reports on Form 8-K

No reports on Form 8-K were filed during the quarter ended June 30, 2001.

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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.

EDISONMISSIONENERGY(Registrant)

|Date: August 13, 2001 |  |  | /s/KEVIN M. SMITHKEVIN M. SMITH
Senior Vice President and Chief Financial Officer
|--------------------- |  |  | ---------------------------------------------------------------------------------

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