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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 September 30, 2001

or

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

Delaware(State or other jurisdiction of
incorporation or organization)

95-4031807(I.R.S. Employer Identification No.)18101 Von Karman Avenue
Irvine, California(Address of principal executive offices)

92612(Zip Code)


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

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

Number
of shares outstanding of the registrant's Common Stock as of November 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 |  | 19  
|3.                           |  | Quantitative and Qualitative Disclosures About Market Risk                            |  | 51  
|PART IIOther Information   
|6.                           |  | Exhibits and Reports on Form 8-K                                                      |  | 52  
|                             |  | Signatures                                                                            |  | 53  

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PART IFINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(In thousands)

|                                                                                                 |                                                                  | Three Months Ended
September 30, |            | Nine Months Ended
September 30, |          
|------------------------------------------------------------------------------------------------ | ---------------------------------------------------------------- | -------------------------------- | ---------- | ------------------------------- | ---------
|
|
|Operating Revenues                                                                               |                                                                  |                                  |            |                                 |          
|                                                                                                 | Electric revenues                                                |                                  | $          | 1,016,505                       |          
|                                                                                                 | Equity in income from energy projects                            |                                  |            | 119,785                         |          
|                                                                                                 | Equity in income from oil and gas investments                    |                                  |            | 12,365                          |          
|                                                                                                 | Net gains (losses) from energy trading and price risk management |                                  |            | 9,476                           |          
|                                                                                                 | Operation and maintenance services                               |                                  |            | 14,383                          |          
|                                                                                                 |                                                                  |                                  |            |                                 |          
|                                                                                                 |                                                                  | Total operating revenues         |            |                                 | 1,172,514
|                                                                                                 |                                                                  |                                  |            |                                 |          
|Operating Expenses                                                                               |                                                                  |                                  |            |                                 |          
|                                                                                                 | Fuel                                                             |                                  |            | 345,959                         |          
|                                                                                                 | Plant operations                                                 |                                  |            | 241,061                         |          
|                                                                                                 | Operation and maintenance services                               |                                  |            | 7,085                           |          
|                                                                                                 | Depreciation and amortization                                    |                                  |            | 101,743                         |          
|                                                                                                 | Long-term incentive compensation                                 |                                  |            | 5,609                           |          
|                                                                                                 | Asset impairment charges                                         |                                  |            | 1,923,574                       |          
|                                                                                                 | Administrative and general                                       |                                  |            | 43,070                          |          
|                                                                                                 |                                                                  |                                  |            |                                 |          
|                                                                                                 |                                                                  | Total operating expenses         |            |                                 | 2,668,101
|                                                                                                 |                                                                  |                                  |            |                                 |          
|                                                                                                 | Operating income (loss)                                          |                                  |            | (1,495,587                      | )        
|                                                                                                 |                                                                  |                                  |            |                                 |          
|Other Income (Expense)                                                                           |                                                                  |                                  |            |                                 |          
|                                                                                                 | Interest and other income                                        |                                  |            | 6,205                           |          
|                                                                                                 | Gain on sale of assets                                           |                                  |            | 41,886                          |          
|                                                                                                 | Interest expense                                                 |                                  |            | (171,523                        | )        
|                                                                                                 | Dividends on preferred securities                                |                                  |            | (5,041                          | )        
|                                                                                                 | Minority interest                                                |                                  |            | (11,140                         | )        
|                                                                                                 |                                                                  |                                  |            |                                 |          
|                                                                                                 |                                                                  | Total other income (expense)     |            |                                 | (139,613 
|                                                                                                 |                                                                  |                                  |            |                                 |          
|                                                                                                 | Income (loss) before income taxes                                |                                  |            | (1,635,200                      | )        
|                                                                                                 | Provision (benefit) for income taxes                             |                                  |            | (594,010                        | )        
|                                                                                                 |                                                                  |                                  |            |                                 |          
|Income (Loss) Before Accounting Change                                                           |                                                                  |                                  | (1,041,190 | )                               |          
|Cumulative effect of change in accounting for derivatives, net of tax                            |                                                                  |                                  | 14,896     |                                 |          
|Cumulative effect on prior years of change in accounting for major maintenance costs, net of tax |                                                                  |                                  |           |                                 |          
|                                                                                                 |                                                                  |                                  |            |                                 |          
|Net Income (Loss)                                                                                |                                                                  | $                                | (1,026,294 | )                               | $        
|                                                                                                 |                                                                  |                                  |            |                                 |          

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

1

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EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

|                                                  |                                                                         | Three Months Ended
September 30,                                                                                                                                                                                      |            | Nine Months Ended
September 30, |        
|------------------------------------------------- | ----------------------------------------------------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---------- | ------------------------------- | -------
|
|
|Net Income (Loss)                                 |                                                                         | $                                                                                                                                                                                                                     | (1,026,294 | )                               | $      
|Other comprehensive income (expense), net of tax: |                                                                         |                                                                                                                                                                                                                       |            |                                 |        
|                                                  | Foreign currency translation adjustments:                               |                                                                                                                                                                                                                       |            |                                 |        
|                                                  |                                                                         | Foreign currency translation adjustments, net of income tax expense (benefit) of $1,725 and $(1,008) for the three months and $(940) and $(4,435) for the nine months ended September 30, 2001 and 2000,
respectively |            |                                 | 42,908 
|                                                  |                                                                         | Reclassification adjustments for planned sale of investment in a foreign subsidiary                                                                                                                                   |            |                                 | 64,065 
|                                                  | Unrealized gains (losses) on derivatives qualified as cash flow hedges: |                                                                                                                                                                                                                       |            |                                 |        
|                                                  |                                                                         | Cumulative effect of change in accounting for derivatives, net of income tax benefit of $13.5 million and $124.4 million for the three months and nine months ended September 30, 2001, respectively                  |            |                                 | (15,506
|                                                  |                                                                         | Other unrealized holding gains (losses) arising during period, net of income tax expense of $5.5 million and $74.3 million for the three months and nine months ended September 30, 2001, respectively                |            |                                 | (17,533
|                                                  |                                                                         | Reclassification adjustments included in net income (loss), net of income tax expense (benefit) of $7.9 million and $(9.7) million for the three months and nine months ended September 30, 2001, respectively        |            |                                 | (10,565
|                                                  |                                                                         |                                                                                                                                                                                                                       |            |                                 |        
|Other comprehensive income (expense)              |                                                                         |                                                                                                                                                                                                                       | 63,369     |                                 |        
|                                                  |                                                                         |                                                                                                                                                                                                                       |            |                                 |        
|Comprehensive Income (Loss)                       |                                                                         | $                                                                                                                                                                                                                     | (962,925   | )                               | $      
|                                                  |                                                                         |                                                                                                                                                                                                                       |            |                                 |        

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

2

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EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

|                              |                                                                                  | September 30,
2001                |            | December 31,
2000
|----------------------------- | -------------------------------------------------------------------------------- | --------------------------------- | ---------- | -----------------
|
|Assets                       
|Current Assets                |                                                                                  |                                   |            |                  
|                              | Cash and cash equivalents                                                        |                                   | $          | 735,600          
|                              | Accounts receivabletrade, net of allowance of $4,609 in 2001 and $1,126 in 2000 |                                   |            | 476,317          
|                              | Accounts receivableaffiliates                                                   |                                   |            | 120,268          
|                              | Assets under energy trading and price risk management                            |                                   |            | 103,517          
|                              | Inventory                                                                        |                                   |            | 308,296          
|                              | Prepaid expenses and other                                                       |                                   |            | 60,207           
|                              |                                                                                  |                                   |            |                  
|                              |                                                                                  | Total current assets              |            |                  
|                              |                                                                                  |                                   |            |                  
|Investments                   |                                                                                  |                                   |            |                  
|                              | Energy projects                                                                  |                                   |            | 1,787,144        
|                              | Oil and gas                                                                      |                                   |            | 28,734           
|                              |                                                                                  |                                   |            |                  
|                              |                                                                                  | Total investments                 |            |                  
|                              |                                                                                  |                                   |            |                  
|Property, Plant and Equipment |                                                                                  |                                   | 9,546,203  |                  
|                              | Less accumulated depreciation and amortization                                   |                                   |            | 938,755          
|                              |                                                                                  |                                   |            |                  
|                              |                                                                                  | Net property, plant and equipment |            |                  
|                              |                                                                                  |                                   |            |                  
|Other Assets                  |                                                                                  |                                   |            |                  
|                              | Long-term receivables                                                            |                                   |            | 270,478          
|                              | Goodwill                                                                         |                                   |            | 627,024          
|                              | Deferred financing costs                                                         |                                   |            | 131,701          
|                              | Long-term assets under energy trading and price risk management                  |                                   |            | 4,007            
|                              | Restricted cash and other                                                        |                                   |            | 118,696          
|                              |                                                                                  |                                   |            |                  
|                              |                                                                                  | Total other assets                |            |                  
|                              |                                                                                  |                                   |            |                  
|Total Assets                  |                                                                                  | $                                 | 13,379,437 |                  
|                              |                                                                                  |                                   |            |                  

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

3

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EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

|                                                |                                                                                                   | September 30,
2001                         |            | December 31,
2000 |          
|----------------------------------------------- | ------------------------------------------------------------------------------------------------- | ------------------------------------------ | ---------- | ----------------- | ---------
|
|Liabilities and Shareholder's Equity            |                                                                                                  
|Current Liabilities                             |                                                                                                   |                                            |            |                   |          
|                                                | Accounts payable  affiliates                                                                     |                                            | $          | 14,405            |          
|                                                | Accounts payable and accrued liabilities                                                          |                                            |            | 519,547           |          
|                                                | Liabilities under energy trading and price risk management                                        |                                            |            | 50,543            |          
|                                                | Interest payable                                                                                  |                                            |            | 132,491           |          
|                                                | Short-term obligations                                                                            |                                            |            | 505,900           |          
|                                                | Current portion of long-term incentive compensation                                               |                                            |            | 1,680             |          
|                                                | Current maturities of long-term obligations                                                       |                                            |            | 1,188,212         |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total current liabilities                  |            |                   | 2,412,778
|                                                |                                                                                                   |                                            |            |                   |          
|Long-Term Obligations Net of Current Maturities |                                                                                                   |                                            | 6,829,591  |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Long-Term Deferred Liabilities                  |                                                                                                   |                                            |            |                   |          
|                                                | Deferred taxes and tax credits                                                                    |                                            |            | 941,549           |          
|                                                | Deferred revenue                                                                                  |                                            |            | 409,534           |          
|                                                | Long-term incentive compensation                                                                  |                                            |            | 40,819            |          
|                                                | Long-term liabilities under energy trading and price risk management                              |                                            |            | 168,839           |          
|                                                | Other                                                                                             |                                            |            | 297,578           |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total long-term deferred liabilities       |            |                   | 1,858,319
|                                                |                                                                                                   |                                            |            |                   |          
|Total Liabilities                               |                                                                                                   |                                            | 11,100,688 |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Minority Interest                               |                                                                                                   |                                            | 356,720    |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Preferred Securities of Subsidiaries            |                                                                                                   |                                            |            |                   |          
|                                                | Company-obligated mandatorily redeemable security of partnership holding solely parent debentures |                                            |            | 150,000           |          
|                                                | Subject to mandatory redemption                                                                   |                                            |            | 93,663            |          
|                                                |                                                                                                   |                                            |            |                   |          
|                                                |                                                                                                   | Total preferred securities of subsidiaries |            |                   | 243,663  
|                                                |                                                                                                   |                                            |            |                   |          
|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                                                                        |                                            |            | 2,630,619         |          
|                                                | Retained earnings (deficit)                                                                       |                                            |            | (713,647          | )        
|                                                | Accumulated other comprehensive loss                                                              |                                            |            | (302,736          | )        
|                                                |                                                                                                   |                                            |            |                   |          
|Total Shareholder's Equity                      |                                                                                                   |                                            | 1,678,366  |                   |          
|                                                |                                                                                                   |                                            |            |                   |          
|Total Liabilities and Shareholder's Equity      |                                                                                                   | $                                          | 13,379,437 |                   | $        
|                                                |                                                                                                   |                                            |            |                   |          

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

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EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

|                                                     |                                                                                          | Nine Months Ended
September 30,                       |         
|---------------------------------------------------- | ---------------------------------------------------------------------------------------- | ----------------------------------------------------- | --------
|
|
|Cash Flows From Operating Activities                 |                                                                                          |                                                       |         
|                                                     | Net income (loss)                                                                        |                                                       | $       
|                                                     | Adjustments to reconcile net income (loss) to net cash provided by operating activities: |                                                       |         
|                                                     |                                                                                          | Equity in income from energy projects                 |         
|                                                     |                                                                                          | Equity in income from oil and gas investments         |         
|                                                     |                                                                                          | Distributions from energy projects                    |         
|                                                     |                                                                                          | Dividends from oil and gas investments                |         
|                                                     |                                                                                          | Depreciation and amortization                         |         
|                                                     |                                                                                          | Deferred taxes and tax credits                        |         
|                                                     |                                                                                          | Amortization of discount on short-term obligations    |         
|                                                     |                                                                                          | Gain on sale of assets                                |         
|                                                     |                                                                                          | Asset impairment charges                              |         
|                                                     |                                                                                          | Cumulative effect of change in accounting, net of tax |         
|                                                     | (Increase) decrease in accounts receivable                                               |                                                       |         
|                                                     | Increase in inventory                                                                    |                                                       |         
|                                                     | (Increase) 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 operating activities             |         
|                                                     |                                                                                          |                                                       |         
|Cash Flows From Financing Activities                 |                                                                                          |                                                       |         
|                                                     | Borrowings on long-term obligations                                                      |                                                       |         
|                                                     | Payments on long-term obligations                                                        |                                                       |         
|                                                     | Short-term financing, net                                                                |                                                       |         
|                                                     | Cash dividends to parent                                                                 |                                                       |         
|                                                     | Issuance of preferred securities                                                         |                                                       |         
|                                                     | Redemption of preferred securities                                                       |                                                       |         
|                                                     |                                                                                          |                                                       |         
|                                                     |                                                                                          | Net cash provided by (used in) financing activities   |         
|                                                     |                                                                                          |                                                       |         
|Cash Flows From Investing Activities                 |                                                                                          |                                                       |         
|                                                     | Investments in and loans to energy projects                                              |                                                       |         
|                                                     | Purchase of generating stations                                                          |                                                       |         
|                                                     | Purchase of common stock of acquired companies                                           |                                                       |         
|                                                     | Capital expenditures                                                                     |                                                       |         
|                                                     | Proceeds from sale-leaseback transactions                                                |                                                       |         
|                                                     | Proceeds from sale of interest in projects                                               |                                                       |         
|                                                     | Decrease in restricted cash                                                              |                                                       |         
|                                                     | Investments in other assets                                                              |                                                       |         
|                                                     | Other, net                                                                               |                                                       |         
|                                                     |                                                                                          |                                                       |         
|                                                     |                                                                                          | Net cash provided by (used in) investing activities   |         
|                                                     |                                                                                          |                                                       |         
|Effect of exchange rate changes on cash              |                                                                                          |                                                       | (26,560 
|                                                     |                                                                                          |                                                       |         
|Net increase (decrease) in cash and cash equivalents |                                                                                          |                                                       | (227,265
|Cash and cash equivalents at beginning of period     |                                                                                          |                                                       | 962,865 
|                                                     |                                                                                          |                                                       |         
|Cash and cash equivalents at end of period           |                                                                                          | $                                                     | 735,600 
|                                                     |                                                                                          |                                                       |         

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

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EDISON MISSION ENERGY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 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 nine months ended September 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.

On
October 26, 2001, we changed our corporate domicile from California to Delaware. The change in domicile was accomplished through a merger between Edison Mission Energy, a
corporation incorporated under the laws of the State of California, and Edison Mission Energy, a Delaware corporation newly formed for this purpose, with the Delaware corporation as the surviving
corporation. As a result, the Delaware corporation succeeded to and assumed all rights and obligations of the California corporation. Apart from the change in our state of incorporation, the change in
corporate domicile had no effect on our business, management, employees, fiscal year, assets or liabilities, or locations of our facilities, including corporate headquarters, and did not result in any
relocation of management or other employees. We filed a Form 8-K on October 29, 2001, which describes our change in domicile in further detail.

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

Mission Energy Holding Company

On June 8, 2001, our ultimate parent company, Edison International created Mission Energy Holding Company as a wholly-owned indirect subsidiary. Mission
Energy Holding's principal asset is our common stock. 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

6

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business activities, as set forth in the Mission Energy Holding financing documents, without shareholder approval.

California Power Crisis

Edison International 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. During the period between summer 2000 and spring 2001, various market conditions and other factors 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., were operating under a retail rate freeze. As a result, there was
a significant under recovery of costs by Southern California Edison and Pacific Gas and Electric, and each of these companies failed to make payments due to power suppliers, including us, and others.
Pacific Gas and Electric filed a voluntary bankruptcy petition on April 6, 2001. The recently announced settlement of the federal district lawsuit between Southern California Edison and the
California Public Utilities Commission, which would allow Southern California Edison to recover certain procurement-related liabilities, may mitigate the situation;
however, given the magnitude of its payment defaults, it is still possible that Southern California Edison could face bankruptcy. 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

Accounting for Derivatives

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

7

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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 September 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 the prior accounting policy. On
January 1, 2001, we recorded a $6 million, after tax, increase to net income and a $230.2 million, after tax, decrease to other comprehensive income as the cumulative effect of
change in accounting for derivatives. During the quarter ended September 30, 2001, we recorded a $17.5 million, after tax, decrease to other comprehensive income resulting from
unrealized holding losses on interest rate swaps of our affiliates. We also recorded a net gain of $0.5 million and $2.2 million for the quarter ended and nine months ended
September 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 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 under Statement
No. 133 Implementation Issue Number C15 modified the normal sales and purchases exception to include electricity contracts which include terms that require physical delivery by the seller in
quantities that are expected to be sold in the normal course of business. Accordingly, we qualified to use the normal sales and purchases exception for our Homer City forward sales contracts
commencing July 1, 2001. Based on this accounting guidance, on July 1, 2001, we eliminated the value of the Homer City forward sales contracts from our consolidated balance sheet. The
cumulative effect of this change in accounting is reflected as a $15.5 million, after tax, decrease to other comprehensive income.

We
had previously applied the normal sales and purchases exception for long-term commodity contracts entered into by our First Hydro plant to buy and sell electricity for
the period between January 1, 2001 through June 30, 2001. However, the criteria applicable to the buyer of power outlined under Statement No. 133 Implementation Issue Number C15
precluded the contracts from qualifying under the normal sales and purchases exception as of July 1, 2001. Accordingly, we recorded a $14.9 million, after tax, increase to net income as
the cumulative effect of change in accounting for derivatives in the consolidated income statement as of July 1, 2001. All subsequent changes in the fair value of these contracts will be
reflected in net gains (losses) from energy trading and price risk management in the consolidated income statement.

Currently,
we are using the normal sales and purchases exception for the majority of our fuel supply agreements. However, the Derivative Implementation Group of the Financial
Accounting Standards Board under Statement No. 133 Implementation Issue Number C16 precludes contracts that have variable quantities from qualifying under the normal sales and purchases
exception. Accordingly, we are evaluating the impact of this implementation guidance, which will be effective on April 1, 2002.

8

---

Accounting for Major Maintenance Costs

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 effect of change in accounting for major maintenance costs during the quarter ended March 31, 2000.

NOTE 3. INVENTORY

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

September 30, 2001

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

$
235.7

$
207.8Spare parts, materials and supplies


72.6


72.1Total

$
308.3

$
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              |  | $                                | (146.7 | )                                             | $ |                                              |  
|Current period change                     |  |                                  | 5.7    |                                               |   | (161.7                                        | )
|                                          |  |                                  |        |                                               |   |                                               |  
|Balance at September 30, 2001 (Unaudited) |  | $                                | (141.0 | )                                             | $ | (161.7                                        | )
|                                          |  |                                  |        |                                               |   |                                               |  

Unrealized
gains (losses) on cash flow hedges at September 30, 2001 included interest rate swaps of our affiliates and the hedge agreement we have with the State Electricity
Commission of Victoria for electricity prices from our Loy Yang B project in Australia. This contract could not qualify under the normal sales and purchases exception because financial settlement of
the contract occurs without physical delivery. Approximately 69% of our accumulated other comprehensive loss at September 30, 2001 related to unrealized losses on the cash flow hedge resulting
from this contract. These losses arise from current forecasts of future electricity prices in these markets 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 $1.8 million, after tax, of the net unrealized losses on cash flow hedges will be reclassified into earnings during the last
quarter 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

9

---

those forecasted transactions related to the payment of variable interest on existing financial instruments, is 15 years.

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, of which 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. From June 1, 2001 to
September 30, 2001, we issued $95.3 million through one of our subsidiaries new preferred securities primarily 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. See "Management's Discussion and Analysis of Financial Condition and Results of
OperationsRecent Developments" for a discussion of a tender offer for the shares held by others in Contact Energy.

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 sold our 25% interest in the Hopewell project and on September 20, 2001, we sold our 50% interest in the Saguaro project for a total gain on sale of
$47.2 million ($26.3 million after tax). During the third quarter of 2001, we entered into agreements, subject to obtaining consents from third parties and other conditions precedent to
closing, for the sale of our interests in the EcoEléctrica, Gordonsville, Commonwealth Atlantic, James River and Nevada Sun-Peak projects. For the quarter ended
September 30, 2001, we recorded asset impairment charges of $24.5 million related to the James River and Nevada Sun-Peak projects based on the expected sales proceeds. We
expect the total net proceeds from the sale of our interests in the above projects, if all are completed, will be approximately $460 million. In addition, we are currently offering for sale our
interest in the Brooklyn Navy Yard project.

On
October 8, 2001, we announced the sale of the Ferrybridge and Fiddler's Ferry power plants in the United Kingdom to two wholly-owned subsidiaries of American Electric Power
for an aggregate

10

---

purchase price of £650 million. The sale is the result of a competitive bidding process. As a result of the transaction, we recorded an asset impairment charge of
$1.9 billion ($1.154 billion after tax) to write down the carrying amount of the power plants to estimated fair value less cost to sell and related currency adjustments. This charge was
recorded in the third quarter of 2001. We expect the transaction to close before the end of 2001. See "Management's Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital ResourcesSubsidiary Financing PlansStatus of Edison First Power Loan."

Pro Forma Financial Information

The following unaudited pro forma financial information summarizes our consolidated results of operations and our subsidiaries excluding the results of
operations of the Ferrybridge and Fiddler's Ferry plants, including the impairment charge discussed above, for the periods indicated. These results have been prepared for comparative purposes only and
do not represent the historical results of
operations in accordance with generally accepted accounting principles as reflected in our consolidated statements of income (loss).

Nine Months Ended
September 30,2001

2000(Unaudited)
(in millions)Operating Revenues

$
2,383.0

$
2,001.7Operating Expenses


1,631.9


1,354.5Other Income (Expense)


(378.5
)

(403.1
)Income Before Accounting Change


195.5


125.4Cumulative Change in Accounting


15.1


21.8Net Income


210.6


147.2


11

---

NOTE 6. COMMITMENTS AND CONTINGENCIES

Capital Commitments

The following table summarizes our consolidated capital commitments as of September 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                               |  | $300                     |   | 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 |  | 43                       |   | 2001-2002   |  | Environmental Matters and Regulations                                                                                                                    
|Project Acquisition for the Italian Wind Projects      |  | 9                        |   | 2001-2002   |  | Firm Commitment for Asset Purchase                                                                                                                       
|Equity Contribution for the Sunrise Project            |  | 116                      |   | 2001-2003   |  | Firm Commitments to Contribute Project Equity                                                                                                            
|Equity Contribution for the Italian Wind Projects      |  | 2                        |   | 2001-2002   |  | Firm Commitments to Contribute Project Equity                                                                                                            
|Equity Contribution for the CBK Project                |  | 59                       |   | 2003        |  | Firm Commitments to Contribute Project Equity                                                                                                            

---

12

---

Firm Commitment for Asset Purchase

Project

Local Currency

(in millions)
U.S. CurrencyItalian Wind(i)

18 billion Italian Lira

$
8.5


---

Firm Commitments to Contribute Project Equity

Projects

Local Currency

(in millions)
U.S. CurrencyItalian Wind(i)

3 billion Italian Lira

$
1.5CBK(ii)




58.5Sunrise(iii)




116.4


---

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

We have 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
we 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, we provide a

13

---

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 September 30, 2001, if payment were required, would be $242 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

During the period between summer 2000 and spring 2001, various market conditions and other factors 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, were operating under a retail rate freeze. As a result, there was a
significant under recovery of costs by Southern California Edison and Pacific Gas and Electric, and each of these companies failed to make

14

---

payments due to power suppliers, including us, and others. Pacific Gas and Electric filed a voluntary bankruptcy petition on April 6, 2001. The recently announced settlement of the federal
district lawsuit between Southern California Edison and the California Public Utilities Commission, which would allow Southern California Edison to recover certain procurement-related liabilities, may
mitigate the situation; however, given the magnitude of its payment defaults, it is still possible that Southern California Edison could face bankruptcy. Edison International 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 $494.6 million at September 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 signed an agreement providing for an extension of the Phase I Agreement from July 1, 2001 to September 30, 2001. The lenders approved this extension of the Phase
I Agreement. All fixed payments totaling $59 million due under that extension of the Phase I Agreement have been made by PT PLN. Paiton Energy and PT PLN have been actively negotiating a
Long-Term Agreement and have made substantial progress. However, that Long-Term Agreement was not completed prior to the expiry of the extension of the Phase I Agreement.
Paiton Energy and PT PLN have therefore signed an agreement providing for an additional extension of this Phase I Agreement to December 31, 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 September 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.

15

---

Brooklyn Navy Yard

Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. Our wholly-owned subsidiary owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of
$136.8 million. Brooklyn Navy Yard Cogeneration Partners has asserted general monetary claims against the contractor. In connection with a $407 million non-recourse project
refinancing in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner from all claims and costs arising from or in connection with the contractor litigation, which
indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. Additional amounts, if any, which would be due to the contractor with respect to completion of construction of the
power plant would be accounted for as an 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

(in millions)
U.S. CurrencyPaiton(i)



$
5.3ISAB(ii)

88 billion Italian Lira


41.6


---



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

16

---

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 |  
|----------------------- |  | -------- | ------- | ------------ | - | -------------------------------------------- |  | ---------------- | -------- | ----- | -
|
|September 30, 2001      |  |          |         |              |   |                                              |  |                  |          |       |  
|Operating revenues      |  | $        | 783.5   |              | $ | 195.7                                        |  | $                | 192.3    |       | $
|Operating income (loss) |  |          | 405.4   |              |   | 59.9                                         |  |                  | (1,916.2 | )     |  
|Total assets            |  | $        | 6,644.6 |              | $ | 3,046.4                                      |  | $                | 3,157.4  |       | $
|September 30, 2000      |  |          |         |              |   |                                              |  |                  |          |       |  
|Operating revenues      |  | $        | 733.1   |              | $ | 51.3                                         |  | $                | 265.9    |       | $
|Operating income        |  |          | 372.2   |              |   | 28.6                                         |  |                  | 67.3     |       |  
|Total assets            |  | $        | 6,905.9 |              | $ | 2,666.2                                      |  | $                | 4,809.6  |       | $

|Nine Months Ended       |  | Americas |         | Asia Pacific |   | Europe,
Central Asia,
Middle East and
Africa |  | Corporate/
Other |          | Total |  
|----------------------- |  | -------- | ------- | ------------ | - | -------------------------------------------- |  | ---------------- | -------- | ----- | -
|
|September 30, 2001      |  |          |         |              |   |                                              |  |                  |          |       |  
|Operating revenues      |  | $        | 1,695.5 |              | $ | 341.4                                        |  | $                | 719.1    |       | $
|Operating income (loss) |  |          | 634.0   |              |   | 130.9                                        |  |                  | (1,843.3 | )     |  
|Total assets            |  | $        | 6,644.6 |              | $ | 3,046.4                                      |  | $                | 3,157.4  |       | $
|September 30, 2000      |  |          |         |              |   |                                              |  |                  |          |       |  
|Operating revenues      |  | $        | 1,430.7 |              | $ | 148.8                                        |  | $                | 930.9    |       | $
|Operating income (loss) |  |          | 453.3   |              |   | 75.6                                         |  |                  | 275.4    |       |  
|Total assets            |  | $        | 6,905.9 |              | $ | 2,666.2                                      |  | $                | 4,809.6  |       | $

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 a 50 percent, 50 percent and 49 percent interest, respectively.

Three Months
Ended
September 30,

Nine Months
Ended
September 30,2001

2000

2001

2000(Unaudited) (in millions)Operating Revenues

$
242.2

$
298.5

$
1,036.4

$
592.3Operating Income


126.2


126.2


357.3


214.9Net Income


142.8


118.7


374.0


214.3


17

---

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
September 30,

Nine Months
Ended
September 30,2001

2000

2001

2000(Unaudited) (in millions)Operating Revenues

$
73.4

$
106.0

$
271.4

$
275.7Operating Income


43.4


58.5


185.8


149.7Net Income


27.5


36.7


116.2


92.6


18

---



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 September 30, 2001, we owned
interests in 32 domestic and 41 international operating power projects with an aggregate generating capacity of 27,931 megawatts (MW), of which our share was 22,993 MW. At that date, one domestic and
five international projects, totaling 1,383 MW of generating capacity, of which our anticipated share will be approximately 842 MW, were in construction. At September 30, 2001, we had
consolidated assets of $13.4 billion and total shareholder's equity of $1.7 billion.

Our
operating revenues are derived primarily from electric revenues and equity in income from power projects. Electric revenues accounted for 87% and 90% of our total operating
revenues during the three-month periods ended September 30, 2001 and 2000, respectively, and 86% and 93% of our total operating revenues during the nine-month periods ended
September 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, of which 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. From June 1, 2001 to
September 30, 2001, we issued $95.3 million through one of our subsidiaries new preferred securities primarily 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

19

---

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. See "Recent Developments" for a discussion of a tender offer for
the shares held by others in Contact Energy.

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 sold our 25% interest in the Hopewell project and on September 20, 2001, we sold our 50% interest in the Saguaro project for a total gain on sale of
$47.2 million ($26.3 million after tax).
During the third quarter of 2001, we entered into agreements, subject to obtaining consents from third parties and other conditions precedent to closing, for the sale of our interests in the
EcoEléctrica, Gordonsville, Commonwealth Atlantic, James River and Nevada Sun-Peak projects. For the quarter ended September 30, 2001, we recorded asset impairment
charges of $24.5 million related to the James River and Nevada Sun-Peak projects based on the expected sales proceeds. We expect the total net proceeds from the sale of our
interests in the above projects, if all are completed, will be approximately $460 million. In addition, we are currently offering for sale our interest in the Brooklyn Navy Yard project.

On
October 8, 2001, we announced the sale of the Ferrybridge and Fiddler's Ferry power plants in the United Kingdom to two wholly-owned subsidiaries of American Electric Power
for an aggregate purchase price of £650 million. The sale is the result of a competitive bidding process. As a result of the transaction, we recorded an asset impairment charge of
$1.9 billion ($1.154 billion after tax) to write down the carrying amount of the power plants to estimated fair value less cost to sell and related currency adjustments. This charge was
recorded in the third quarter of 2001. We expect the transaction to close before the end of 2001. 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. 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

20

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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
September 30, |       | Nine Months
Ended
September 30, |  
|---------------------------------------------------------------- | ------------------------ | -------------------------------- | ----- | ------------------------------- | -
|
|
|Operating revenues                                               |                          | $                                | 652.5 |                                 | $
|Net gains (losses) from energy trading and price risk management |                          |                                  | 3.7   |                                 |  
|Equity in income from investments                                |                          |                                  | 127.3 |                                 |  
|                                                                 |                          |                                  |       |                                 |  
|                                                                 | Total operating revenues |                                  |       | 783.5                           |  
|Fuel and plant operations                                        |                          |                                  | 301.7 |                                 |  
|Depreciation and amortization                                    |                          |                                  | 46.0  |                                 |  
|Asset impairment charges                                         |                          |                                  | 24.5  |                                 |  
|Administrative and general                                       |                          |                                  | 5.9   |                                 |  
|                                                                 |                          |                                  |       |                                 |  
|                                                                 | Operating income         |                                  | $     | 405.4                           |  
|                                                                 |                          |                                  |       |                                 |  

Operating Revenues

Operating revenues increased $8.4 million and $58.5 million for the third quarter and nine months ended September 30, 2001, respectively,
compared to the corresponding periods of 2000. The increase resulted from higher electric revenues from the Homer City plant due to increased production and higher energy prices, as compared to the
same prior year period. The increase in the third quarter of 2001 was partially offset by lower electric revenues from the Illinois Plants due to lower dispatch of their coal units as a result of
lower market prices during the third quarter of 2001.

Net
gains from energy trading activities were $3.1 million and $5.5 million for the third quarter and nine months ended September 30, 2001, respectively. Net
losses from energy trading activities from September 1, 2000, the acquisition date of Citizens Power, to September 30, 2000 were $1.4 million. Total gains and losses from price
risk management activities increased $10 million and $73.9 million for the third quarter and nine months ended September 30, 2001, respectively, compared to the corresponding
periods of 2000. The increase in gains was primarily due to realized and unrealized gains for a gas swap purchased to hedge a portion of our gas price risk related to our share of gas

21

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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 transactions of investments accounted for on the equity method. Partially offsetting this gain in the third quarter and nine months ended September 30, 2001 was
a loss resulting from the change in market value of future contracts with respect to a portion of our anticipated fuel purchases through 2002 at the Illinois Plants that did not qualify for hedge
accounting under SFAS No. 133.

Equity
in income from investments increased $27.5 million and $125.5 million during the third quarter and nine months ended September 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 nine-month period ended
September 30, 2001 and revenues from the Sunrise project, which commenced operations in June 2001. We had no comparable results for the Sunrise project in 2000.

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 $73 million for the nine months ended September 30, 2001, compared to the same prior year period. 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 through the period ended August 2000. In addition, plant operations increased due to higher
maintenance costs at the Illinois Plants during the nine-month period ended September 30, 2001.

Depreciation
and amortization expense decreased $4.1 million and $25 million for the third quarter and nine months ended September 30, 2001, respectively,
compared to the corresponding periods of the prior 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 on August 24, 2000.

Asset
impairments of $24.5 million were required to write down our investments to the estimated net proceeds from the planned sale of the James River and Nevada
Sun-Peak projects. During the third quarter of 2001, we entered into agreements, subject to obtaining consents from third parties and other conditions precedent to closing, for the sale of
our 50% interest in these projects. We expect to reach financial close during the fourth quarter of 2001. For more information on the domestic asset sales, see "Acquisitions and
DispositionsDispositions."

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

Operating Income

Operating income increased $33.2 million and $180.7 million during the third quarter and nine months ended September 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.

22

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Asia Pacific

|                                                         |                          | Three Months
Ended
September 30, |       | Nine Months
Ended
September 30,
|-------------------------------------------------------- | ------------------------ | -------------------------------- | ----- | -------------------------------
|
|
|Operating revenues                                       |                          | $                                | 196.1 |                                
|Net losses from energy trading and price risk management |                          |                                  | (1.8  | )                              
|Equity in income from investments                        |                          |                                  | 1.4   |                                
|                                                         |                          |                                  |       |                                
|                                                         | Total operating revenues |                                  |       | 195.7                          
|Fuel and plant operations                                |                          |                                  | 115.6 |                                
|Depreciation and amortization                            |                          |                                  | 20.2  |                                
|                                                         |                          |                                  |       |                                
|                                                         | Operating income         |                                  | $     | 59.9                           
|                                                         |                          |                                  |       |                                

Operating Revenues

Operating revenues increased $149.3 million and $194.8 million for the third quarter and nine months ended September 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.

Net
losses from price risk management activities were $1.8 million and $1.7 million for the third quarter and nine months ended September 30, 2001, respectively.
There were no comparable gains or losses for the same prior year periods. The losses primarily resulted from the change in the market value of interest rate swaps and options that did not qualify for
hedge accounting under SFAS No. 133. The losses were partially offset by gains that represent the ineffective portion of a long-term contract with the State Electricity
Commission of Victoria entered into by the Loy Yang B plant, which is a derivative that qualified as a cash flow hedge under SFAS No. 133. See "Note 4. Accumulated
Other Comprehensive Income (Loss)" for further discussion.

Equity
in income from investments decreased $3.1 million during the quarter ended September 30, 2001, compared to the same prior year period. The decrease primarily
reflects Contact Energy being accounted for on a consolidated basis effective June 1, 2001, compared to the equity method of accounting prior to the acquisition of a controlling interest.

Operating Expenses

Fuel and plant operations increased $101.7 million and $127.4 million for the third quarter and nine months ended September 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.

Depreciation
and amortization expense increased $11.4 million and $9.9 million for the third quarter and nine months ended September 30, 2001, respectively,
compared to the same prior year periods. The increase primarily reflects the consolidation of Contact Energy depreciation and amortization expenses, effective June 1, 2001.

Operating Income

Operating income increased $31.3 million and $55.3 million during the third quarter and nine months ended September 30, 2001,
respectively, compared to the corresponding periods of 2000. The

23

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increase was primarily due to consolidating Contact Energy's results of operations, effective June 1, 2001. Prior to June 1, 2001, we used the equity method of accounting for Contact
Energy.

Europe, Central Asia, Middle East and Africa

|                                                                 |                          | Three Months
Ended
September 30, |         | Nine Months
Ended
September 30, |  
|---------------------------------------------------------------- | ------------------------ | -------------------------------- | ------- | ------------------------------- | -
|
|
|Operating revenues                                               |                          | $                                | 182.3   |                                 | $
|Net gains (losses) from energy trading and price risk management |                          |                                  | 6.6     |                                 |  
|Equity in income (loss) from investments                         |                          |                                  | 3.4     |                                 |  
|                                                                 |                          |                                  |         |                                 |  
|                                                                 | Total operating revenues |                                  |         | 192.3                           |  
|Fuel and plant operations                                        |                          |                                  | 176.8   |                                 |  
|Depreciation and amortization                                    |                          |                                  | 32.6    |                                 |  
|Asset impairment charges                                         |                          |                                  | 1,899.1 |                                 |  
|                                                                 |                          |                                  |         |                                 |  
|                                                                 | Operating income (loss)  |                                  | $       | (1,916.2                        | )
|                                                                 |                          |                                  |         |                                 |  

Operating Revenues

Operating revenues decreased $86.1 million and $214.2 million for the third quarter and nine months ended September 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 a 6.8% decrease in the average exchange rate of the pound sterling compared to the U.S. dollar at the nine-month period ended September 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 energy prices for the six-month period ended September 30, 2001, compared to
the six-month period ended September 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
gains (losses) from price risk management activities were $6.6 million and $(7.5) million for the third quarter and nine months ended September 30, 2001,
respectively. There were no comparable gains or losses for the same prior year periods. The gains in the third quarter of 2001 primarily represent the change in market value of long-term
commodity contracts entered into by the First Hydro plant for the purchase and sale of electricity that were recorded at fair value under SFAS No. 133 with changes in fair value recorded
through the income statement, effective July 1, 2001. The losses for the nine months ended September 30, 2001 primarily represent the change in market value of electricity rate swap
agreements entered into by the Ferrybridge and Fiddler's Ferry plants 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 $9.9 million during the third quarter and nine months ended September 30, 2001, respectively,
compared to the same prior year periods. The increase reflects gains from the ISAB project, which commenced operations in April 2000, due to

24

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increased generation in 2001. We had no comparable results for the ISAB project in the first quarter of 2000.

Operating Expenses

Fuel and plant operations increased $13.8 million and $12.5 million for the third quarter and nine months ended September 30, 2001,
respectively, compared to the corresponding periods in 2000. The
increase for the three-month period ended September 30, 2001, was primarily due to higher fuel costs at the Ferrybridge and Fiddler's Ferry plants and at the First Hydro plant. Fuel costs were
higher at the Ferrybridge and Fiddler's Ferry plants due to increased coal purchases used for resale to third parties as the opportunity to sell coal was greater in the current year. Fuel costs
increased at the First Hydro plant due to higher overnight prices and charges from the grid under the new electricity trading arrangements (commonly referred to as "imbalance charges"). The new
electricity trading arrangements are described in further detail under "Market Risk ExposuresUnited Kingdom." The increase in fuel expense for the nine-month
period ended September 30, 2001, primarily resulted from higher fuel costs at the Doga plant due to increased production in 2001, compared to the same prior year period.

Asset
impairment charges of $1.9 billion were required to write down the carrying amount of the Ferrybridge and Fiddler's Ferry plants to their estimated fair value less cost
to sell and related currency adjustments in connection with the announced sale of the plants. The announced sale is described in further detail under "Acquisitions and
DispositionsDispositions."

Operating Income (Loss)

Operating loss totaled $1.9 billion and $1.8 billion during the third quarter and nine months ended September 30, 2001, respectively,
compared to operating income of $67.3 million and $275.4 million during the third quarter and nine months ended September 30, 2000, respectively. The decrease was primarily due to
an operating loss from the Ferrybridge and Fiddler's Ferry plants resulting from the asset impairment charge recorded during the third quarter of 2001.

Corporate/Other

|                                                        |                         | Three Months Ended
September 30, |      | Nine Months Ended
September 30, |  
|------------------------------------------------------- | ----------------------- | -------------------------------- | ---- | ------------------------------- | -
|
|
|Net gains from energy trading and price risk management |                         | $                                | 1.0  |                                 | $
|Depreciation and amortization                           |                         |                                  | 3.0  |                                 |  
|Long-term incentive compensation                        |                         |                                  | 5.6  |                                 |  
|Administrative and general                              |                         |                                  | 37.1 |                                 |  
|                                                        |                         |                                  |      |                                 |  
|                                                        | Operating income (loss) |                                  | $    | (44.7                           | )
|                                                        |                         |                                  |      |                                 |  

Net
gains from price risk management activities were $1 million and $2.3 million for the third quarter and nine months ended September 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. Long-term incentive compensation expense increased
$60 million and $57.1 million for the third quarter and nine months ended September 30, 2001, respectively, compared to the corresponding periods of the prior year. The increase
was due to a reduction in the liability for previously accrued

25

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incentive compensation by approximately $60 million recorded during the third quarter of 2000. This reduction resulted from the lower valuation implicit in the August 2000 exchange offer
pursuant to which the phantom option plan was terminated compared to the value previously accrued. During the nine months ended September 30, 2001, we recorded an adjustment to our
long-term incentive compensation accrual for changes in the market value of stock equivalent units.

Other Income (Expense)

Interest and other income decreased $11.9 million and $6.4 million for the third quarter and nine months ended September 30, 2001,
respectively, compared to the same prior year periods. The decrease was primarily due to lower foreign exchange gains on intercompany loans. Lower interest income due to lower cash balances also
contributed to the decrease in the third quarter of 2001.

Gains
on sale of assets were $41.9 million and $45.5 million for the third quarter and nine months ended September 30, 2001, respectively, compared to
$8.5 million and $25.4 million during the same prior year periods. Gains on the sale of assets included:

Project

Net Proceeds

Ownership Interest Sold

DateSaguaro

$
67.0

50
%
September 20, 2001Hopewell


26.5

25

June 29, 2001Kwinana


12.0

30

August 16, 2000Auburndale


22.0

50

June 30, 2000


Interest
expense decreased $5.7 million and $43.4 million for the third quarter and nine months ended September 30, 2001, respectively, compared to the same prior
year periods. The decrease was primarily the result of lower interest rates on debt financing associated with the Illinois Plants and favorable changes in foreign exchange rates.

Dividends
on mandatorily redeemable preferred securities decreased $3 million and $7 million for the third quarter and nine months ended September 30, 2001,
respectively, compared to the same prior year periods. The decrease reflects the redemption of the NZ$400 million EME Taupo preferred securities in July 2001.

Minority
interest expense increased $10.2 million and $16.2 million for the third quarter and nine months ended September 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 nine months ended September 30, 2001, we recorded an effective tax benefit rate of 36% based on projected income for the year and benefits
under our tax sharing agreement, compared to the annual effective tax provision rate for the first nine months of 2000 of 44%. The change in the effective income tax rate is largely due to changes in
income levels in different international tax jurisdictions.

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.

26

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Cumulative Effect of Change in Accounting Principle

Accounting for Derivatives

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 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 September 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 the prior accounting policy. On
January 1, 2001, we recorded a $6 million, after tax, increase to net income and a $230.2 million, after tax, decrease to other comprehensive income as the cumulative effect of
change in accounting for derivatives. During the quarter ended September 30, 2001, we recorded a $17.5 million, after tax, decrease to other comprehensive income resulting from
unrealized holding losses on interest rate swaps of our affiliates. We also recorded a net gain of $0.5 million and $2.2 million for the quarter ended and nine months ended
September 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.

27

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The Derivative Implementation Group of the Financial Accounting Standards Board has 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 under Statement
No. 133 Implementation Issue Number C15 modified the normal sales and purchases exception to include electricity contracts which include terms that require physical delivery by the seller in
quantities that are expected to be sold in the normal course of business. Accordingly, we qualified to use the normal sales and purchases exception for our Homer City forward sales contracts
commencing July 1, 2001. Based on this accounting guidance, on July 1, 2001, we eliminated the value of the Homer City forward sales contracts from our consolidated balance sheet. The
cumulative effect of this change in accounting is reflected as a $15.5 million, after tax, decrease to other comprehensive income.

We
had previously applied the normal sales and purchases exception for long-term commodity contracts entered into by our First Hydro plant to buy and sell electricity for
the period between January 1, 2001 through June 30, 2001. However, the criteria applicable to the buyer of power outlined under Statement No. 133 Implementation Issue Number C15
precluded the contracts from qualifying under the normal sales and purchases exception as of July 1, 2001. Accordingly, we recorded a $14.9 million, after tax, increase to net income as
the cumulative effect of change in accounting for derivatives in the consolidated income statement as of July 1, 2001. All subsequent changes in the fair value of these contracts will be
reflected in net gains (losses) from energy trading and price risk management in the consolidated income statement.

Currently,
we are using the normal sales and purchases exception for the majority of our fuel supply agreements. However, the Derivative Implementation Group of the Financial
Accounting Standards Board under Statement No. 133 Implementation Issue Number C16 precludes contracts that have variable quantities from qualifying under the normal sales and purchases
exception. Accordingly, we are evaluating the impact of this implementation guidance, which will be effective on April 1, 2002.

Accounting for Major Maintenance Costs

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 effect of change in accounting for major maintenance costs during the quarter ended March 31, 2000.

Liquidity and Capital Resources

In September 2001, we entered into a new $750 million corporate credit facility. We used this new credit facility, together with other corporate
funds, to replace our existing corporate credit facilities scheduled to mature in October 2001 and repay all outstanding borrowings thereunder. At September 30, 2001, we had cash and
cash equivalents of $735.6 million and had available a total of $41.2 million of borrowing capacity under our $750 million corporate credit facility. At October 31, 2001,
borrowing capacity under the corporate credit facility increased to $239 million due to expiration of overlapping letters of credit as well as debt paydown from available corporate funds. The
new credit facility includes a one-year $538.3 million component, Tranche A, that expires on September 16, 2002 and a three-year $211.7 million component,
Tranche B, that expires on September 17, 2004. The credit facility provides credit available in the form of cash advances or letters of credit. At September 30, 2001, Tranche A consisted
of one borrowing and bears interest under the one-month London Interbank

28

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Offered Rate of 2.785%, effective September 21, 2001 through October 22, 2001, plus the applicable margin as determined by our long-term credit ratings (all in rate of
5.16%). Tranche B, which had no advances outstanding at September 30, 2001, did include the issuance of letters of credit in the amount of $208.8 million. In addition to the interest
payments, we pay a facility fee as determined by our long-term credit ratings (0.625% and 0.75% at September 30, 2001 for Tranche A and Tranche B, respectively) on the entire credit
facility independent of the level of borrowings. See "Corporate Financing Plans."

Discussion of Historical Cash Flow

Net cash provided by operating activities totaled $33.9 million during the nine months ended September 30, 2001, compared to
$348.3 million for the corresponding period of the prior year. The decrease is primarily due to higher working capital requirements, partially offset by higher distributions from energy
projects and higher dividends from oil and gas investments. Net working capital at September 30, 2001 was ($608.6) million compared to ($1,703.9) million at December 31, 2000.

Net
cash provided by financing activities totaled $127.7 million for the nine months ended September 30, 2001, compared to net cash used in financing activities of
$834 million for the nine months ended September 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 August 2001, we issued $400 million of 10% senior notes due 2008, the proceeds of which were used to permanently repay on our corporate credit facilities. Dividends
totaling $65 million and $32.5 million were paid to The Mission Group and Mission Energy Holding Company, respectively, and ultimately $96.5 million was paid to Edison
International, our ultimate parent company, during the nine-month period ended September 30, 2001, compared to $66 million during the same prior year period. As of
September 30, 2001, we had recourse debt of $2.5 billion, with an additional $6 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 totaled $362.3 million for the nine months ended September 30, 2001, compared to net cash provided by investing activities of
$965 million for the nine months ended September 30, 2000. In 2001, net cash used in investing activities was 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 the nine-month period ended
September 30, 2001. See "The California Power Crisis and Our Response" for further discussion. In addition, through September 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. In June 2001, we also completed the sale of a 50% interest in the Sunrise project to Texaco for
$84 million. In 2000, net cash provided by investing activities was primarily due to proceeds of $1.367 billion and $300 million received from the sale leaseback transactions with
respect to the Powerton and Joliet power facilities in August 2000 and the Illinois peaker power units in July 2000, respectively. In connection with the Illinois peaker power units
transaction, we purchased $255 million of notes issued by the lessor. Through September 30, 2000, $27 million was paid towards the purchase price and $13 million in equity
contributions for the Italian Wind projects and $44.9 million for the Citizens trading operations and structured transaction investments. In addition, $33.5 million, $21.2 million
and $20 million were made in equity contributions for the EcoEléctrica project (June 2000), Tri Energy project (July 2000) and the ISAB project
(September 2000), respectively. We invested $200.5 million and $221.5 million during the nine-month

29

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periods ended September 30, 2001 and 2000, respectively, in new plant equipment principally related to the Homer City plant, Illinois Plants and Ferrybridge and Fiddler's Ferry plants in 2001
and the Homer City plant and Illinois Plants in 2000.

Corporate Financing Plans

As discussed above, we have one $750 million corporate credit facility as of September 30, 2001. Our expected corporate cash payments during the
next twelve months include:



In
addition, we:



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 believe that our existing cash resources and corporate financing plans will provide us sufficient liquidity to meet our cash requirements during the next twelve months, although no assurance can be
provided in this regard.

Subsidiary Financing Plans

The estimated capital and construction expenditures of our subsidiaries for the fourth quarter of 2001 are $102 million. These 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. From June 1, 2001 to
September 30, 2001, we issued $95.3 million through one of our subsidiaries new preferred

30

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securities primarily 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. See "Recent Developments" for a discussion of a tender offer for the shares held by others in Contact Energy.

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 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 for the period between January 1, 2001 and June 30, 2001. In September 2001, Edison First Power utilized £17 million from its debt service reserve
and paid £36 million to meet its semi-annual debt service requirements of £53 million for the period between July 1, 2001 and
December 31, 2001.

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, the Coal and CapEx
Facility, related to the Fiddler's Ferry and Ferrybridge power plants. At September 30, 2001, £68 million was outstanding for coal purchases and
£56 million 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 our
guarantee remains in force notwithstanding any breaches under Edison First Power's acquisition financing documents. Obligations under this facility are due in 2004.

As
a result of the change in the prices of power in the U.K., we offered for sale through a competitive bidding process the Ferrybridge and Fiddler's Ferry power plants. On
October 8, 2001, we

31

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announced the sale of the power plants to two wholly-owned subsidiaries of American Electric Power for an aggregate purchase price of £650 million. The power plants were acquired in
1999 from PowerGen UK plc for £1.3 billion. We expect the transaction to close before the end of 2001. We plan to use the proceeds from the sale, if it closes, to repay the
acquisition financing of the project. The early repayment of the project's existing debt facility related to the acquisition of the power plants of £682.2 million at
September 30, 2001 is expected to result in an extraordinary loss of approximately $30 million, attributable to the write-off of unamortized debt issue costs. American
Electric Power needs to obtain certain regulatory clearances before completing the plant purchase. Although the relevant applications are currently being processed, there is no guarantee that these
will be granted. In August 2000, we commenced arbitration proceedings against PowerGen for claims totaling approximately £95 million primarily related to the purchase price
of the power plants. PowerGen denies all of the claims. In July 2001, the arbitration hearing took place, and we anticipate a ruling to be made before the end of 2001. The proceeds, if any,
from this matter will be recorded when the matter is resolved and used to repay borrowings under the Coal and CapEx Facility. We plan to repay the Coal and CapEx Facility from cash flows generated
from foreign subsidiaries prior to its maturity in 2004.

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. While we
cannot assure you that TEAS will make its payments on a timely basis, such payment obligations are guaranteed by the Turkish Treasury. Currently, permission is being sought from the lenders to
determine if Doga Enerji will make a distribution for 2001.

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 were required to pay Edison International $55 million
during October 2001 as a result of changes in estimated taxable income for 2000. At September 30, 2001, we have recorded $110.4 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 taxable income in order
to be able to monetize our tax losses 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:



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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 below investment grade could increase our cost of capital, increase our credit support obligations, make efforts to raise capital more difficult,
adversely affect our trading operations, and 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.

Commitments and Contingencies

Capital Commitments

The following table summarizes our consolidated capital commitments as of September 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                               |  | $300                     |   | 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 |  | 43                       |   | 2001-2002   |  | Environmental Matters and Regulations                                                                                                                    
|Project Acquisition for the Italian Wind Projects      |  | 9                        |   | 2001-2002   |  | Firm Commitment for Asset Purchase                                                                                                                       
|Equity Contribution for the Sunrise Project            |  | 116                      |   | 2001-2003   |  | Firm Commitments to Contribute Project Equity                                                                                                            
|Equity Contribution for the Italian Wind Projects      |  | 2                        |   | 2001-2002   |  | Firm Commitments to Contribute Project Equity                                                                                                            
|Equity Contribution for the CBK Project                |  | 59                       |   | 2003        |  | Firm Commitments to Contribute Project Equity                                                                                                            

---

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Firm Commitment for Asset Purchase

Project

Local Currency

(in millions)
U.S. CurrencyItalian Wind(i)

18 billion Italian Lira

$
8.5


---

Firm Commitments to Contribute Project Equity

Projects

Local Currency

(in millions)
U.S. CurrencyItalian Wind(i)

3 billion Italian Lira

$
1.5CBK(ii)




58.5Sunrise(iii)




116.4


---

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

We have 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

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be available until December 31, 2001, after which time we 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, we provide 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 September 30, 2001, if payment were required, would be $242 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

During the period between summer 2000 and spring 2001, various market conditions and other factors resulted in higher wholesale power prices to California
utilities. At the same time, two of the

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three major California utilities, Southern California Edison and Pacific Gas and Electric Co., were operating under a retail rate freeze. As a result, there was a significant under recovery of costs
by Southern California Edison and Pacific Gas and Electric, and each of these companies failed to make payments due to power suppliers, including us, and others. Pacific Gas and Electric filed a
voluntary bankruptcy petition on April 6, 2001. The recently announced settlement of the federal district lawsuit between Southern California Edison and the California Public Utilities
Commission, which would allow Southern California Edison to recover certain procurement-related liabilities, may mitigate the situation; however, given the magnitude of its payment defaults, it is
still possible that Southern California Edison could face bankruptcy. Edison International 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 $494.6 million at September 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 signed an agreement providing for an extension of the Phase I Agreement from July 1, 2001 to September 30, 2001. The lenders approved this extension of the Phase
I Agreement. All fixed payments totaling $59 million due under that extension of the Phase I Agreement have been made by PT PLN. Paiton Energy and PT PLN have been actively negotiating a
Long-Term Agreement and have made substantial progress. However, that Long-Term Agreement was not completed prior to the expiry of the extension of the Phase I Agreement.
Paiton Energy and PT PLN have therefore signed an agreement providing for an additional extension of this Phase I Agreement to December 31, 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 September 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.

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Brooklyn Navy Yard

Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. Our wholly-owned subsidiary owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of
$136.8 million. Brooklyn Navy Yard Cogeneration Partners has asserted general monetary claims against the contractor. In connection with a $407 million non-recourse project
refinancing in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner from all claims and costs arising from or in connection with the contractor litigation, which
indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. Additional amounts, if any, which would be due to the contractor with respect to completion of construction of the
power plant would be accounted for as an 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

(in millions)
U.S. CurrencyPaiton(i)



$
5.3ISAB(ii)

88 billion Italian Lira


41.6


---

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

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before taxes from these partnerships was $168 million, which represented 20% of our operating income. Our investment in these partnerships at September 30, 2001 was
$515.2 million.

Utility Payment Defaults

As a result of Southern California Edison's and Pacific Gas and Electric's current liquidity crisis, each of these utilities 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. The California utilities'
failure to pay has adversely affected the operations of our eight California qualifying facilities. Similarly, continuing failures to pay could have an adverse impact on the operations of our
California qualifying facilities.

As
a result of the utilities' failure to make payments due to our California qualifying facilities, some of the partnerships which own these facilities have called on the partners to
provide additional capital to fund operating costs of the power plants. From January 1, 2001 to September 30, 2001, some of our subsidiaries 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.

Pacific Gas and Electric

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. 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.

Effective
as of July 31, 2001, Pacific Gas and Electric and four of the partnerships in which we have a partnership interest entered into agreements that amended the power
purchase agreements to provide for a fixed energy price for the lesser of the remaining term of the power purchase agreement or five years. The contract amendments have been approved by both the
bankruptcy court and the California Public Utilities Commission. Pacific Gas and Electric has assumed the power purchase agreements, as amended, and is making assumption payments of the
past-due amounts on an agreed schedule.

On
September 20, 2001, Pacific Gas and Electric and its parent corporation jointly filed a proposed plan of reorganization with the bankruptcy court. Under the plan, unsecured
creditors would receive payment for 60 percent of their allowed claims in cash and 40 percent in long-term notes. The proposed
reorganization plan will not become effective unless it is approved by the bankruptcy court and other conditions precedent are met or waived before January 1, 2003. Under the terms of our four
agreements with Pacific Gas and Electric, the entire cure amount, if and to the extent not already paid pursuant to the assumption payments discussed above, becomes due and payable upon the effective
date of the reorganization plan.

Southern California Edison

Southern California Edison did not pay qualifying facilities, including four partnerships in which we have an interest, 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. At September 30, 2001, accounts receivable due to these partnerships from Southern California Edison were
$401.9 million. Our share of these receivables was $199.6 million.

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Provisions in the relevant 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.

All
four of the partnerships in which we have an interest filed complaints against Southern California Edison with respect to the payment defaults. All of those partnerships have
since entered into agreements with Southern California Edison, under which the partnerships and Southern California Edison are to 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. Southern California Edison has already paid the first 10% of the past due amounts and has also begun making monthly interest payments on the past due amounts.

Southern
California Edison and the owners of qualifying facilities, including partnerships in which we have a partnership interest, are discussing the impact on their standstill
agreements of the settlement agreement between Southern California Edison and the California Public Utilities Commission, which is discussed in more detail below. Southern California Edison has stated
that it does not expect to seek any legislative action in the immediate future, because it believes that the settlement agreement substantially resolves the issues that would have been addressed by
the Legislature. However, Southern California Edison has taken the position with the partnerships that, while the settlement agreement may have resolved the same issues that restorative legislation
would have addressed, it does not trigger further payments of past due amounts to the partnerships under the standstill agreements.

It
is unclear at this time what additional actions, if any, the partnerships will take in regard to the position taken by Southern California Edison under the standstill agreements,
or to any future suspension of payments due to the qualifying facilities by the utilities, or in the event that the standstill agreements cease to be in effect. 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 the
standstill agreements between the partnerships and Southern California Edison 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. 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. Southern California Edison has also stated that it expects that the settlement agreement should enable it to repay its
past due obligations in the first quarter of 2002. However, it is possible that Southern California Edison will not pay all its obligations in full. In addition, despite the settlement agreement, 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.
Also, Southern California

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Edison's power purchase agreements with the qualifying facilities could be subject to review by a bankruptcy court.

Regulatory and Legislative Developments

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. This decision 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.

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. 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. Neither of these draft decisions have been put to
a vote before the Commission. 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.

On
April 9, 2001, Edison International and Southern California Edison signed a Memorandum of Understanding with the California Department of Water Resources. The Memorandum
called for legislation, regulatory action and definitive agreements to resolve important aspects of the energy crisis.

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Among other things, the Memorandum provided that we would 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. This contract was executed on June 25, 2001, and the first phase of the Sunrise project became operational on June 27, 2001. Despite
the developments described below, we expect that this contract will continue in effect.

The
parties agreed in the Memorandum that each of its elements was part of an integrated package, and effectuation of each element would depend upon effectuation of the others. To
implement the Memorandum, numerous actions were to be taken by the parties and by other agencies of the State of California, including the enactment of legislation by the California Legislature. The
California Legislature completed its regular session business on September 14, 2001 without passing legislation to implement the Memorandum or otherwise restore the creditworthiness of Southern
California Edison. However, the Governor of California called a special session of the Legislature to address such legislation, which was to have begun on October 9, 2001.

On
October 2, 2001, the California Public Utilities Commission announced an agreement with Southern California Edison to settle a federal district court lawsuit filed in late
2000 seeking a ruling that Southern California Edison is entitled to full recovery of its costs for wholesale purchases of electricity. The settlement agreement provides for Southern California Edison
to recover its procurement-related liabilities, less cash on hand and certain other amounts, through a regulatory balancing account with a starting balance of approximately $3.3 billion. The
recovery will take place out of the positive or negative difference of Southern California Edison's revenues from retail electric rates (including
surcharges) over authorized costs. The parties agreed that Southern California Edison will recover its procurement-related obligations by December 31, 2005; and they projected that existing
rates will likely result in Southern California Edison recovering substantially all of its unrecovered procurement-related obligations prior to the end of 2003. The settlement agreement also provides
that, subject to certain qualifications, Southern California Edison will cooperate with the California Public Utilities Commission and the California Attorney General to pursue and resolve claims and
rights against sellers of energy and related services.

On
October 5, 2001, the federal district court signed and entered a stipulated judgment approving the terms of the settlement agreement. One of the intervenors in the lawsuit,
a consumer advocacy group known as The Utility Reform Network, filed a notice of its intent to appeal the stipulated judgment and also filed a motion with the Ninth Circuit Court of Appeals requesting
a stay of the stipulated judgment pending resolution of its appeal. On October 30, 2001, the Ninth Circuit Court of Appeals remanded the motion for stay to the federal district court, and
issued a temporary stay of the stipulated judgment pending resolution of the matter by the federal district court. On November 9, 2001, the federal district court denied the consumer group's
motion for a stay of the stipulated judgment. The consumer group has until November 15, 2001, to ask the Ninth Circuit Court of Appeals for a stay of the stipulated judgment pending appeal. If
the stay of stipulated judgment pending appeal is granted, or the settlement is successfully challenged on appeal, the ability of Southern California Edison and the California Public Utilities
Commission to implement the settlement agreement would be affected adversely, which in turn would have an adverse effect on Southern California Edison's ability to restore its financial condition,
repay its creditors and avoid an involuntary bankruptcy petition. The other intervenor, the County of Los Angeles, has stated publicly that it will not appeal the stipulated judgment.

Following
the announcement of the settlement agreement, the Governor of California stated that, in light of the settlement, there was no need for a special session of the Legislature
and he rescinded his call of a special session. Southern California Edison has stated that it does not expect to seek any legislative action in the immediate future, because it believes that the
settlement agreement substantially resolves the issues that would have been addressed by the Legislature.

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A number of other 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. The price mitigation measures end on September 30, 2002. 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. The proceedings have been delayed due
to difficulties with the underlying data necessary to calculate refunds, and currently no decision is expected until the first quarter of 2002 at the earliest. A separate proceeding was also conducted
to evaluate the potential for refunds in the Pacific Northwest. The administrative law judge in that proceeding recommended that refunds not be ordered, on the basis of a finding that the Pacific
Northwest market was workably competitive. The Federal Energy Regulatory Commission has not yet acted on the administrative law judge's recommended disposition of the matter. The federal and state,
legislative and regulatory initiatives may result in a restructuring of the California power market. A California voter initiative or referendum has been threatened against any measures that would
raise consumer rates or aid California's investor-owned utilities. At this time, it is not possible to estimate the likely ultimate outcome of these activities.

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

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"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 our assets and liabilities 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.

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

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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. Exelon Generation provided us notice to continue the agreement related to
the coal units and the Collins Station for 2002. In October 2001, Exelon Generation terminated the power purchase agreement for the peaker units with respect to 309 megawatts of oil peakers,
effective January 2002, but continued the agreement for all other peaker plants 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 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

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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 Hedge. Additionally, the Loy
Yang B plant has entered into a number of derivative contracts to further mitigate against price volatility inherent in the electricity pool. These contracts consist of fixed forward electricity
contracts commencing either in 2001 or 2002, which expire on various dates through December 31, 2002, and a five-year cap contract commencing January 1, 2002 and expiring
December 31, 2006.

New Zealand.A substantial portion of Contact Energy's generation output is hedged by sales to retail electricity customers and forward
contracts with other wholesale electricity counterparties. Contact Energy has entered into forward contracts and option contracts of varying terms that expire on various dates through
September 30, 2003. The New Zealand Government commissioned an inquiry into the electricity industry in February 2000. Following the inquiry report the New Zealand Government released a
Government Policy Statement, at the center of which was a call for the industry to rationalize the three existing industry codes, form a single governance structure and address transmission
pricing methodology. The Government Policy Statement also requested a model use of system agreement be agreed, that is a framework by which the retailers contract for services from each of the
distribution networks, and a consumer complaints ombudsman be established. An essential theme perpetuated throughout the Government Policy Statement was the desire that the industry retain a private
multilateral self-governing structure. During 2001, an amendment to the Electricity Act of 1992 was passed that laid out the form that regulation would take if the industry does not heed
the Government's call. Progress on the single governance code is well underway and the Chairs of the three existing codes report to the Minister of Energy every two months on progress. The new code is
likely to be introduced in July 2002.

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
$13.5 million and $13.3 million of additional interest expense for the nine months ended September 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. On September 28,
2001, our NZ$50 million interest rate swap expired.

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We had short-term obligations of $505.9 million consisting of bank borrowings and commercial paper at September 30, 2001. The fair values of these
obligations approximated their carrying values at September 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
$8.3 billion at September 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 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 Australia, New Zealand and the U.K. decreased in value compared to the U.S. dollar by 11%, 8% and 2%, respectively (determined by the change in the exchange
rates from December 31, 2000 to September 30, 2001). The decrease in value of these currencies was the primary reason for the foreign currency translation loss of $58.4 million
during the first nine months of 2001.

In
December 2000, Ferrybridge and Fiddler's Ferry entered into foreign currency forward exchange contracts in the ordinary course of business to protect itself 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 September 30,
2001, the outstanding notional amount of the contracts totaled $57 million, consisting of contracts to exchange U.S. dollars to pound sterling with varying maturities ranging from
October 2001 to July 2002. During the first nine months of 2001, we
recognized a foreign exchange gain of approximately $85,000 related to the fuel purchases underlying the contracts that matured during the first nine months of 2001.

Contact
Energy enters into foreign currency forward exchange contracts in the ordinary course of business to offset certain operational and balance sheet exposures from changes in the
value of the New Zealand dollar. The contracts are primarily in Australian and U.S. dollars with varying maturities through September 2002. At September 30, 2001, the net sold position
of the foreign exchange contracts totaled $1.1 million. During the four-month period ended September 30, 2001, Contact Energy recognized a foreign exchange gain of $547,000
related to the contracts that matured during the same period.

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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 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.

StateIllinois

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.

FederalUnited States of America

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 $14.5 million for the fourth quarter of 2001 and $12.2 million in 2002 to install
upgrades to the environmental controls at the Homer City plant to reduce sulfur dioxide and nitrogen oxide emissions. Similarly, we anticipate upgrades to the environmental controls at the Illinois
Plants to reduce nitrogen oxide emissions to result in expenditures of approximately $11.3 million for the fourth quarter of 2001 and $388.8 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 $4.9 million for the fourth quarter of 2001.

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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 controls, 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 above the upgrades we are planning to install, and could be subject to fines and penalties. We cannot estimate the outcome of these discussions or the potential costs of
investing in additional pollution
control requirements, fines or penalties at this time. 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, which has been extended indefinitely. 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

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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 Environmental Protection Agency 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.

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.

International

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 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

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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.

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

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useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

In
October 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets," which will be effective on January 1, 2002, unless early adoption is implemented. The Statement establishes accounting and reporting standards for the impairment
or disposal of long-lived assets. The Statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of" but retains SFAS No. 121 requirements to recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash
flows and to measure an impairment loss as the difference between the carrying amount and fair value of the asset. However, SFAS No. 144 eliminates the requirement to allocate goodwill to
long-lived assets to be tested for impairment. Long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, are required to be measured at
the lower of its carrying amount or fair value less cost to sell and depreciation is ceased. In addition, SFAS No. 144 extends the reporting of discontinued operations to a component of an
entity that has been disposed of or is classified as held for sale.

We
are studying the impact of the new accounting standards described above and are unable to predict at this time the impact on our consolidated financial statements.

Recent Developments

On October 12, 2001, we announced our intention to acquire the remaining 49% of Contact Energy that we do not own, thereby increasing our ownership
interest to 100%. We proposed an offer of NZ$4.25 per share, including an interim dividend of NZ$0.11 per share, to the minority shareholders payable in cash. The offer commenced on November 6,
2001 and will remain open until December 6, 2001. We expect the transaction to close before the end of 2001. We cannot assure you that the transaction will close as anticipated or at all. In
connection with the foregoing, we have also entered into forward exchange contracts in New Zealand dollars to fund a portion of the purchase price.

Between
early June and mid-October of 2001, our subsidiary, Midwest Generation, and the union that represents the employees at the Illinois Plants were in negotiations to
replace the expired collective bargaining agreement, covering wages and working conditions. The union authorized a strike that began on June 28, 2001. Midwest Generation operated the Illinois
Plants during the strike. Negotiations have concluded with a new four-year agreement that was ratified by the represented employees on October 16, 2001. Pursuant to the
reinstatement process, employees began returning to work on October 22, 2001.

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                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|----------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.1        |  | Indenture, dated as of August 10, 2001, among Edison Mission Energy and The Bank of New York as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the
Securities and Exchange Commission on August 29, 2001.                                                                                                                                                                                            
|10.1.1      |  | Form of 10% Senior Note due 2008 (included in Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001).                                                                                                                                                                                                                                                                                   
|10.2        |  | Registration Rights Agreement, dated as of August 7, 2001, among Edison Mission Energy, Credit Suisse First Boston Corporation, BMO Nesbitt Burns Corp., Salomon Smith Barney Inc., SG Cowen Securities Corporation, TD Securities (USA) Inc. and
Westdeutsche Landesbank Girozentrale (Düsseldorf), incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.
|10.92       |  | Credit Agreement, dated as of September 13, 2001, among Edison Mission Energy, Certain Commercial Lending Institutions, Citicorp USA, Inc., as Administrative Agent, and Citibank, N.A. as Issuing Agent, incorporated by reference to Exhibit 10.92 to
Amendment No. 1 of Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on September 27, 2001.                                                                   

(b)  Reports on Form 8-K

The registrant filed the following report on Form 8-K during the quarter ended September 30, 2001.

Date of Report

Date Filed

Item(s) ReportedAugust 1, 2001

August 1, 2001

7, 9


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SIGNATURES

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

Edison Mission Energy(Registrant)

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

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